Corrosion Control in
The Refining
Industry
January 2010
 NACE International
Corrosion Control in the Refining Industry was originally written in
1999 under the direction of a task group of NACE members from
Group Committee T-8, Refining Industry Corrosion. The basis for
this course was the material from the Corrosion in the Oil Refining
Industry Conferences sponsored by NACE International and Group
Committee T-8.
The members of the original committee were:
H. Lee Craig (Chairman)
Corrosion Prevention and Control
Richmond, VA.
Donald J. Truax
Chevron Research & Technology Company
Richmond, Va.
Ken Marden
Exxon Company USA
Benicia, CA
Sadine Tebbal
Consultant
Sugarland, TX
Ongoing input and technical oversight of the course is provided by a
task group (TG348) of the Specific Technology Group (STG34)
dealing with Petroleum Refining and Gas Processing Corrosion.
IMPORTANT NOTICE
Neither NACE International, its officers, directors, nor members
thereof accept any responsibility for the use of the methods and
materials discussed herein. No authorization is implied concerning
the use of patented or copyrighted material. The information is
advisory only and the use of the materials and methods is solely at
the risk of the user.
It is the responsibility of each person to be aware of current local,
state and national regulations. This course is not intended to
provide comprehensive coverage of regulations.
Printed in the United States. All rights reserved. Reproduction of
contents in whole or part or transfer into electronic storage without
permission of copyright owner is expressly forbidden.
1
Welcome to Corrosion Control in the Refining
Industry!
Introduction
The purpose of Corrosion Control in the Refining Industry is to
provide you with an overview of refinery process units, specific
process descriptions, and the opportunity to identify and examine
corrosion and metallurgical problems that may occur in process
units. You will also examine techniques and practices that may be
used to control corrosion in refineries. This course is designed for
corrosion and equipment engineers, process engineers,
metallurgists, mechanical engineers, inspectors, and suppliers of
corrosion-related products to the refining industry.
Course Design
Corrosion Control in the Refining Industry is presented in a
concentrated format over a four and one-half day period. You will
be given the opportunity during class time to examine the majority
of the material presented in the student manual. The additional
information is provided with the intent that the manual will serve as
valuable reference material once the course has ended.
During the four and a half days of the course, you will become
involved in class discussions and activities, ask questions, exchange
ideas, and gather information. You are encouraged to take notes in
the student manual as the instructor and fellow participants offer
information that enhances the material presented in the manual.
Your active participation adds to your understanding of the course
material.
©NACE International 2007
6/2008
Corrosion Control in the Refining Industry Course Manual
2
Course Topics
The following topics are included in Corrosion Control in the
Refining Industry:
•
Corrosion and Other Failures
•
Crude Distillation and Desalting
•
Fluid Catalytic Cracking Unit
•
Cracked Light Ends Recovery (CLER) Units
•
Hydrofluoric Acid Alkylation Units
•
Sulfuric Acid Alkylation Units
•
Corrosion in Hydroprocessing Units
•
Catalytic Reforming Units
•
Delayed Coking Units
•
Amine Treating Units
•
Sulfur Recovery Units
•
Process Additives and Corrosion Control
•
Corrosion Monitoring Methods in Refineries
•
Refinery Injection Systems
•
Materials of Construction for Refinery Applications
•
Refinery Operations and Overview
•
Failure Analysis in Refineries
Corrosion Control in the Refining Industry Course Manual
©NACE International 2007
6/2008
1
CORROSION CONTROL IN THE REFINING INDUSTRY
TABLE OF CONTENTS
Chapter 1: Corrosion and Other Failures
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Low-Temperature Refinery Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Low-Temperature Corrosion Principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Corrosion Rates and Polarization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Passivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Temperature and Concentration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Low-Temperature Conditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
High-Temperature Refinery Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
High-Temperature Corrosion Principles. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Linear Rate Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Parabolic Rate Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
High-Temperature Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Corrosion/Failure Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Metal Loss—General and/or Localized Corrosion . . . . . . . . . . . . . . . . . . . . . . . 19
Galvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Pitting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Crevice Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Intergranular Attack . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Erosion-Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Hydrogen Chloride . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Ammonium Bisulfide (NH4HS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Carbon Dioxide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Process Chemicals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Organic Chlorides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Aluminum Chloride . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Sulfuric Acid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Hydrofluoric Acid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Phosphoric Acid. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Phenol (Carbolic Acid) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Amines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Atmospheric (External) Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Corrosion Under Insulation (CUI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Soil Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
High-Temperature Sulfide Corrosion (Without Hydrogen Present) . . . . . . . 37
High-Temperature Sulfide Corrosion (With Hydrogen) . . . . . . . . . . . . . . . . 40
Naphthenic Acid Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
High-Temperature Oxidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
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Stress Corrosion Cracking (SCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Chloride Stress Corrosion Cracking (ClSCC) . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Alkaline Stress Corrosion Cracking (ASCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
Carbonic Acid (Wet CO2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51
Polythionic Acid Stress Corrosion Cracking (PTA SCC) . . . . . . . . . . . . . . . . . 52
Ammonia Stress Corrosion Cracking (NH3 SCC) . . . . . . . . . . . . . . . . . . . . . . . 53
Wet H2S Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
Hydrogen Blistering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
Sulfide Stress Cracking (SSC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
Hydrogen Induced Cracking (HIC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Stress Oriented Hydrogen Induced Cracking (SOHIC) . . . . . . . . . . . . . . . . . . . 57
Hydrogen Cyanide (HCN) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
SCC Prevention. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
Inspecting for Wet H2S Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
High-Temperature Hydrogen Attack (HTHA) . . . . . . . . . . . . . . . . . . . . . . . . . . 62
Metallurgical Failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
Grain Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65
Graphitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
Hardening . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
Sensitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67
Sigma Phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67
885°F (475°C) Embrittlement. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
Temper Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
Liquid Metal Embrittlement (LME) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69
Carburization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70
Metal Dusting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70
Decarburization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71
Selective Leaching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71
Mechanical Failures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
Incorrect or Defective Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
Mechanical Fatigue. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
Corrosion Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74
Cavitation Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
Mechanical Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
Overloading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
Overpressuring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78
Brittle Fracture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79
Creep . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80
Stress Rupture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80
Thermal Shock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81
Thermal Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
Other Forms of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
Boiler Feed Water Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
Corrosion Control in the Refining Industry
©NACE International 2008
January 2010
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Steam Condensate Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
Cooling Water Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
Fuel Ash Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84
Chapter 2: Crude Distillation and Desalting
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Sources of Crude Oil. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Composition of Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Remaining Constraints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
More about Crude Oil Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Crude Oil Pretreatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Desalting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Preflash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Crude Distillation Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Operation of a Crude Distillation Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Corrosion in Crude Distillation Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Columns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Exchangers and Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Fired Heaters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Other Corrosion Combating Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Blending . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Desalting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Caustic Addition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Overhead pH Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Corrosion Inhibitor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Water Washing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Corrosion Monitoring in Crude Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Water Analysis (Overhead Corrosion Control) . . . . . . . . . . . . . . . . . . . . . . . . . 27
Hydrocarbon Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Corrosion Rate Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
On-Stream, Non-Destructive Examination. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Optional Team Exercise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Chapter 3: Fluid Catalytic Cracking Units
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Hardware . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Riser/Reactor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Regenerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Flue Gas System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Fractionator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
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Corrosion Control in FCC Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Materials of Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Damage Mechanisms and Suitable Materials . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Reactors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Regenerators. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Catalyst Transfer Piping System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Reaction Mix Line, Main Fractionator, and Bottoms Piping . . . . . . . . . . . . . . . 15
Flue Gas Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Inspection and Control Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
High-Temperature Oxidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
High-Temperature Sulfidation (H2S Attack) . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
High-Temperature Carburization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Polythionic Acid Stress Corrosion Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Catalyst Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Feed Nozzle Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Refractory Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
High-Temperature Graphitization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Sigma Phase Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
885°F (475°C) Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Creep Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
High-Temperature Creep . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Thermal Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Optional Team Exercise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Chapter 4: Cracked Light Ends Recovery Units
CLER Process Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Materials of Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Columns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Exchangers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Corrosion Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Hydrogen Induced Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Inspection Techniques for Hydrogen-Induced Damage . . . . . . . . . . . . . . . . . 7
Prevention and Repair Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Ammonia Stress Corrosion Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Carbonate Stress Corrosion Cracking. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Fouling/Corrosion of Reboiler Circuits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Corrosion Control Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Water Washing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Polysulfide Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Corrosion Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
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Hydrogen-Activity Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Chemical Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Corrosion Probes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Chapter 5: Hydrofluoric Acid Alkylation Units
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
HF Alky Process Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Materials of Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Columns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Exchangers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Bolting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Corrosion Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Hydrogen Induced Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Inspection and Mitigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Corrosion Control Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Corrosion Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Corrosion Probes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Chapter 6: Sulfuric Acid Alkylation Units
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Process Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Reaction Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Treating Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Fractionation Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Refrigeration Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Materials of Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Materials and Corrosion Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Sulfuric Acid Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Acid Concentration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Acid Temperature and Velocity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Acid Dilution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Hydrogen Grooving . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Feed Contaminants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Acid and Neutral Esters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Acid Esters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Neutral Esters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Acid Carryover . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Corrosion Under Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
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Fouling Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Corrosion Control Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Reactor Section Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Tower Overhead Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Reboiler Corrosion and Fouling Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Acid Tanks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Corrosion Control During Unit Shutdowns . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Corrosion Under Insulation (CUI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Corrosion Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Reaction Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Treating Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Fractionation Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Refrigeration Equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Acid Tank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Chapter 7: Hydroprocessing Units
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Hydroprocessing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Hydrotreating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Hydrocracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Variations on Hydroprocessing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Types of Corrosion Common in Hydroprocessing Units . . . . . . . . . . . . . . . . . . . . . 6
High-Temperature Hydrogen Attack . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
High-Temperature H2S Corrosion – With Hydrogen Present . . . . . . . . . . . . . . . 7
High-Temperature H2S Corrosion – With Little or No Hydrogen Present . . . . . 9
Naphthenic Acid Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Ammonium Bisulfide Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Chloride Stress Corrosion Cracking (SCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Failures Often Happen After Startup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Additional Considerations with Stainless Steel . . . . . . . . . . . . . . . . . . . . . . . 13
Polythionic Acid (PTA) Stress Corrosion Cracking. . . . . . . . . . . . . . . . . . . . . . 14
Stainless Steels Used to Prevent PTA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Other Methods to Prevent PTA SCC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Wet H2S Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Sulfide Stress Cracking (SSC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Hydrogen Induced Cracking (HIC) and Stress-Oriented Hydrogen Induced
Cracking (SOHIC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Material Property Degradation Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Temper Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Hydrogen Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Selection of Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
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Reactor Loop – General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Reactor Feed System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Reactor Feed Furnaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Reactors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Reactor Effluent System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Reactor Effluent – Distillation Feed Exchangers . . . . . . . . . . . . . . . . . . . . . . . . 22
Effluent Air Coolers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Effluent Air Cooler Inlet and Outlet Piping . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Separator Vessels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Recycle Hydrogen System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Distillation Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Optional Team Exercise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Chapter 8: Catalytic Reforming Units
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Octane Number (RON) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Catalyst . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Catalytic Reforming Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Catalytic Reformer, Semi-Regenerative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Reactor Design. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Corrosion Phenomena in Catalytic Reformers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
High Temperature Hydrogen Attack (HTHA) . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Stress Corrosion Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Materials of Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Reactors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Exchangers and Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Fired Heaters and Other Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Corrosion Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Corrosion Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Inspection in Catalytic Reformers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Chapter 9: Delayed Coking Units
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Equipment and Operation of the Delayed Coking Unit. . . . . . . . . . . . . . . . . . . . . . . 2
Corrosion and Other Problems in Delayed Coking Units . . . . . . . . . . . . . . . . . . . . . 4
High-Temperature Sulfur Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Naphthenic Acid Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
High-Temperature Oxidation/Carburization/Sulfidation . . . . . . . . . . . . . . . . . . . 6
Decoking Heater Tubes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Erosion-Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
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Aqueous Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Corrosion Under Insulation (CUI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Thermal Fatigue, and Temper Embrittlement of Cr-Mo Steels . . . . . . . . . . . . . 10
Inspection of Coking Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
General Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Coke Drum Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Chapter 10: Amine Treating Units
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Types of Amines Used. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Refinery Amine Process Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Tail Gas Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Corrosion Phenomena . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Corrosive Species . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Amine Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Cracking Phenomena . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Corrosion Inhibitors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Materials of Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Corrosion Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Corrosion Control Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Chapter 11: Sulfur Recovery Units
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Sulfur Recovery Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Sulfur Chemical Reactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Sulfur Recovery Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Tail Gas Treating Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Incinerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Cold Bed Adsorption (CBA) Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Corrosion Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Sulfidation of Carbon Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Sour Environment Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Weak Acid Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Corrosion of Claus Units by System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Feed Gas System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Corrosion Concerns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Mitigation of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Reaction Furnace and Waste Heat Exchanger Systems . . . . . . . . . . . . . . . . . . . 12
Corrosion Concerns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Mitigation of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
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Inspections in the Reaction Furnace and Waste Heat Exchanger System . . . 13
Claus Reactors, Condensers, and Reheat System . . . . . . . . . . . . . . . . . . . . . . . . 14
Corrosion Concerns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Mitigation of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Inspections in the Claus Reactors, Condensers, and Reheat System . . . . . . . 15
Liquid Sulfur Rundown Lines and Storage System . . . . . . . . . . . . . . . . . . . . . . 16
Corrosion Concerns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Mitigation of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Inspections in Liquid Sulfur Rundown Lines and Storage System . . . . . . . . 17
Corrosion of CBA Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Corrosion Concerns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Mitigation of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Inspection of CBA Reactors, Condensers, and Piping. . . . . . . . . . . . . . . . . . 18
Corrosion of Tail Gas Treating Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Burner and Mixing Chamber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Tail Gas Reactor and Waste Heat Exchanger . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Water Quench and Recirculation Blower System . . . . . . . . . . . . . . . . . . . . . . . 20
H2S Adsorption System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Corrosion in the Incinerator System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Chapter 12: Refinery Injection Systems
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Injection Point. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Injection System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Injection System Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Injection System Design Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Engineering Practices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Process Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Materials Selection Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Inspection of Injection Point Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Location of Injection Point . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Co-Injectants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Injection System Hardware. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Chemical Storage Tanks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Chemical Injection Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Additive Control Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Piping Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Injector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
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Chapter 13: Process Additives and Corrosion Control
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Factors Affecting Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Acids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Turbulence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Material Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Methods to Mitigate Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Desalting and Caustic Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Water Washing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Acid Neutralization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Barrier between Metal and Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Chemicals Used to Combat Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Filming Amines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Filmer Formulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Filmer Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Treat Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Monitoring Filmer Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Neutralizing Amines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Polysulfides. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Naphthenic Acid Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Application of Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Chapter 14: Corrosion Monitoring in Refineries
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Uses of Corrosion Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Corrosion Monitoring Techniques. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Corrosion Coupons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Electrical Resistance Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Electrochemical Corrosion Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Linear Polarization Resistance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Potential Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Zero Resistance Ammetry (ZRA). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Electrical Impedance Spectroscopy (EIS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Electrochemical Noise (EN) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Hydrogen Flux Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
A Comprehensive Corrosion Monitoring Program . . . . . . . . . . . . . . . . . . . . . . . . . 19
Corrosion Monitoring Sites . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Corrosion Monitoring in Specific Process Units . . . . . . . . . . . . . . . . . . . . . . . . 23
Atmospheric Distillation Unit (ADU) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
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Vacuum Distillation Unit (VDU). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Fluid Catalytic Cracking Unit (FCCU) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Amine Treating Unit (ATU) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Sour Water Stripper Units (SWSU) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Sulfuric Acid Alkylation Unit (SAU) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Automated On-Line Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Chapter 15: Materials of Construction for Refinery Applications
The Role of the Corrosion Engineer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Problem Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Corrosion Failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Corrosion Testing Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Materials Selection Approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Using Professional Consultants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Specifying Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
National Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Company Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
What the Designer Should Remember When Writing Specifications . . . . . . . . 14
Questions the Designer Should Ask to Control Quality . . . . . . . . . . . . . . . . . . . 16
Fitness for Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Refinery Materials of Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Killed Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Carbon Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
C-Mo Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Low-Alloy Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Cr-Mo Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Nickel Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Martensitic Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Ferritic Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Austenitic Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Precipitation Hardening Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Duplex Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Specialty Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Cast Irons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Gray Cast Irons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Ductile Irons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
High-Silicon Cast Irons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Nickel Cast Irons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Other Metals and Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
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Copper and Its Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Nickel Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Aluminum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Titanium and Its Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Non-Metallic Materials. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Refractories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Plastics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Thermosetting Resins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
Heat Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
Normalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
Annealing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
Quenching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
Stress Relieving . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Solution Heat Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Specialized Heat Treatments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
What the Designer Should Know About Heat Treatments. . . . . . . . . . . . . . . . . 45
Heat Treatment Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Heat Treatment for Welds. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Preheat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Postweld Heat Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Normalizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
Welding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
The Nature of Welding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
Welding Decisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
Welding Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
Shielded Metal Arc Welding (SMAW) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
Gas Metal Arc Welding (GMAW) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
Gas Tungsten Arc Welding (GTAW) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
Submerged Arc Welding (SAW) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
Welding Procedures and Welder Qualification . . . . . . . . . . . . . . . . . . . . . . . . . 55
Inspection of Welding Electrodes and Filler Metal . . . . . . . . . . . . . . . . . . . . . . 56
Chapter 16: Refinery Operations and Overview
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Refinery Operating Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Refining Process Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Process Interactions with Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Corrosion Control in the Refining Industry
©NACE International 2008
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Chapter 17: Failure Analysis in Refineries
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Procedural Approach and Test Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Background Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Initial Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Nondestructive Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Surface Deposit Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Field Metallographic Replication (FMR) . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Hardness Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Chemical Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Magnetic Particle Inspection (MPI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Wet Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Dry Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Dye Penetrant Testing (PT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Sectioning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Macroscopic Examination of Fracture Surfaces . . . . . . . . . . . . . . . . . . . . . . . . . 11
Microscopic Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Fracture Appearance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Ductile Fracture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Brittle Fracture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Fatigue Fractures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Stress Corrosion Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Creep Rupture Failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Additional Testing and Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Mechanical Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Application of Fracture Mechanics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Root Cause Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
©NACE International 2008
January 2010
Corrosion Control in the Refining Industry
14
Appendices
A
NACE Standard MR0103, “Materials Resistant to Sulfide Stress Cracking
in Corrosive Petroleum Environments”
B
NACE Standard TM0284, “Evaluation of Pipeline and Pressure Vessel
Steels for Resistance to Hydrogen-Induced Cracking”
C
NACE Standard TM0177, “Laboratory Testing of Metals for Resistance to
Sulfide Stress Cracking and Stress Corrosion Cracking in H2S
Environments”
D
NACE Standard TM0103, “Laboratory Test Procedures for Evaluation of
SOHIC Resistance of Plate Steels Used in Wet H2S Service”
E
NACE Standard SP0403, “Avoiding Caustic Stress Corrosion Cracking of
Carbon Steel Refinery Equipment and Piping”
F
NACE Publication 34105, “Effect of Nonextractable Chlorides on
Refining Corrosion and Fouling”
G
NACE Recommended Practice SP0472, “Methods and Controls to Prevent
In-Service Environmental Cracking of Carbon Steel Weldments in
Corrosive Petroleum Refining Environments”
H
NACE Standard RP0296, “Guidelines for Detection, Repair, and
Mitigation of Cracking of Existing Petroleum Refinery Pressure Vessels in
Wet H2S Environments”
I
NACE Publication 8X194, “Materials and Fabrication Practices for New
Pressure Vessels to be Used in Wet H2S Refinery Environments”
J
NACE Publication 8X294, “Review of Published Literature on Wet H2S
Cracking of Steels Through 1989”
Corrosion Control in the Refining Industry
©NACE International 2008
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K
NACE Publication 5A171, “Materials for Receiving, Handling, and
Storing Hydorfluoric Acid”
L
NACE Standard RP0391, Materials for Handling and Storage of
Commercial (90 to 100%) Sulfuric Acid at Ambient Temperatures”
M
NACE Recommended Practice SP0294, “Design, Fabrication, and
Inspection of Tanks for the Storage of Concentrated Sulfuric Acid and
Oleum at Ambient Temperatures”
N
NACE Standard RP0205,”Recommended Practice for the Design,
Fabrication and Inspection of Tanks for the Storage of Petroleum Refining
Alkylation Unit Spent Sulfuric Acid at Ambient Temperatures”
O
API Publication 941, “Steels for Hydrogen Service at Elevated
Temperature and Pressure”
P
NACE Recommended Practice RP0170, “Protection of Austenitic
Stainless Steels and Other Austenitic Alloys from Polythionic Acid Stress
Corrosion Cracking During Shutdown of Refinery Equipment”
Q
NACE Publication 34103, “Overview of Sulfidic Corrosion in Petroleum
Refining”
R
NACE Publication 34101, “Refinery Injection and Process Mixing Points”
S
NACE Recommended Practice RP0198, “The Control of Corrosion Under
Thermal Insulation and Fireproofing Materials—A Systems Approach”
T
NACE Standard MR0175/ISO15156-1, “Petroleum and natural gas
industries-Materials for use in H2S-containing Environments in oil and gas
production”
©NACE International 2008
January 2010
Corrosion Control in the Refining Industry
16
U
NACE Standard TM0169, “Laboratory Corrosion Testing of Metals”
V
NACE Standard SP0590, “Recommended Practice for Prevention,
Detection and Correction of Deaerator Cracking”
W
X
Y
UNS Numbers/Composition of Alloys
Z
Glossary of Refinery Corrosion Related Terms
Corrosion Control in the Refining Industry
©NACE International 2008
January 2010
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Corrosion Control in the Refining Industry
List of Figures
Chapter 1: Corrosion and Other Failures
Figure 1.1: Electrochemical Corrosion Cell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Figure 1.2: Linear Rate Law of High-Temperature Corrosion . . . . . . . . . . . . . . . 15
Figure 1.3: Parabolic Rate Law of High-Temperature Corrosion . . . . . . . . . . . . . 17
Figure 1.4: Dry Cell Battery - A typical Example of Galvanic (Electrochemical)
Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Figure 1.5: Corrosion of Steel by Strong Sulfuric Acid as a Function of
Temperature and Concentration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Figure 1.6: Modified McConomy Curves for H2S Corrosion . . . . . . . . . . . . . . . . 38
Figure 1.7: Sulfur Correction Factor for McConomy Curves . . . . . . . . . . . . . . . . 39
Figure 1.8: Modified Couper-Gorman Corrosion Curve—Carbon Steel in
Naphtha Desulfurizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
Figure 1.9: Corrosion Rate Curves for H2S/H2 Environments . . . . . . . . . . . . . . . 42
Figure 1.10: Operating Limits for Steels in Hydrogen Service . . . . . . . . . . . . . . . 63
Chapter 2: Crude Distillation and Desalting
Figure 2.1: Saleable Refinery Products . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Figure 2.2: Boiling Temperature of Water (212°F[100°C]) . . . . . . . . . . . . . . . . . . 6
Figure 2.3: Boiling Temperatures of Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Figure 2.4: Crude Oil Distillation Curve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Figure 2.5: Distillation Curves for Certain Crude Oils . . . . . . . . . . . . . . . . . . . . . 10
Figure 2.6: Desalting Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Figure 2.7: Preflash Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Figure 2.8: Crude Oil Distillation Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Chapter 3: Fluid Catalytic Cracking Units
Figure 3.1: Catalytic Cracker Reaction Chamber . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Figure 3.2: Catalyst Regenerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Figure 3.3: Fractionation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Figure 3.4: Generic Fluid Catalytic Cracking Unit Process Flow Diagram . . . . . . 9
Figure 3.5: Generic Fluid Catalytic Cracking Unit, Materials of Construction . . 11
Figure 3.6: Generic Fluid Catalytic Creacking Unit, Inspection
Summary Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Chapter 4: Cracked Light Ends Recovery Units
Figure 4.1: Cracked Light Ends Recovery Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Figure 4.2: Hydrogen Activity Probe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Corrosion Control in the Refining Industry
©NACE International 2008
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Chapter 5: Hydrofluoric Acid Alkylation Units
Figure 5.1: HF Alkylation Process Flow 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Figure 5.2: Metals and Alloys for HF Acid 13 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Chapter 6: Sulfuric Acid Alkylation Units
Figure 6.1: Typical Auto-Refrigeration Alkylation Plant with Stirred Reactors . . . 3
Figure 6.2: Typical Effluent Refrigeration Alkylation Plant with Contactor-type
Reactor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Figure 6.3: Typical Caustic and Water Wash Facility . . . . . . . . . . . . . . . . . . . . . . . 5
Figure 6.4: Typical Fractionation Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Chapter 7: Hydroprocessing Units
Figure 7.1: Simplified Flow Diagram of Hydrotreater Unit . . . . . . . . . . . . . . . . . . 3
Figure 7.2: Flow Diagram of Single-Stage Hydrocracking Unit . . . . . . . . . . . . . . . 5
Figure 7.3: High-Temperature H2-H2S Corrosion of Carbon Steel . . . . . . . . . . . . 8
Chapter 8: Catalytic Reforming Units
Figure 8.1: Catalytic Reforming, Semi-Regenerative . . . . . . . . . . . . . . . . . . . . . . . 7
Figure 8.2: Cold Shell Reactor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Chapter 9: Delayed Coking Units
Figure 9.1: Delayed Coking Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Chapter 10: Amine Treating Units
Figure 10.1: Refinery Amine Unit with Multiple Absorbers . . . . . . . . . . . . . . . . . 5
Figure 10.2: Quench Tower and Tail Gas Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Chapter 11: Sulfur Recovery Units
Figure 11.1: Flow Diagram for Claus Reactor Unit . . . . . . . . . . . . . . . . . . . . . . . . 4
Figure 11.2: Tail Gas Unit, Amine Adsorption System, and Incinerator . . . . . . . . 6
Chapter 12: Refinery Injection Systems
Figure 12.1: Typical Chemical Injection System . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Corrosion Control in the Refining Industry
©NACE International 2008
January 2010
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Chapter 13: Process Additives and Corrosion Control
Figure 13.1: Formation of Metal from Ore and Corrosion of Metal . . . . . . . . . . . . 2
Figure 13.2: Filming Amine Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Figure 13.3: Classical Filming Amine Mechanism . . . . . . . . . . . . . . . . . . . . . . . . 12
Figure 13.4: Neutralizing Amines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Figure 13.5: Hydrogen Blistering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Chapter 14: Corrosion Monitoring in Refineries
Figure 14.1: Typical Plot of Metal Loss versus Time . . . . . . . . . . . . . . . . . . . . . . . 6
Figure 14.2: Types of Pitting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Figure 14.3: Schematic of ER Probe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Figure 14.4: ER Probe Data versus Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Figure 14.5: Potentiodynamic Polarization Curve . . . . . . . . . . . . . . . . . . . . . . . . . 11
Figure 14.6: LPR Scan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Figure 14.7: Electrochemical Impedance Spectroscopy (EIS) . . . . . . . . . . . . . . . 15
Figure 14.8: Various Kinds of Hydrogen Probes . . . . . . . . . . . . . . . . . . . . . . . . . 17
Figure 14.9: Electrochemical Hydrogen Probe Current versus Time Plot . . . . . . 18
Figure 14.10: Setting of Corrosion Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Figure 14.11: Corrosion Rate versus Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Figure 14.12: Corrosion Monitoring System with Multiple On-Line Probes . . . . 21
Figure 14.13: Output from a Flush-Mounted Multiple Probe . . . . . . . . . . . . . . . . 22
Figure 14.14: Crude Vacuum Distillation Unit and Atmospheric Distillation
Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Figure 14.15: Catalytic Fractionation Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Figure 14.16: Amine Treatment Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Figure 14.17: Non-Acidified Sour Water Stripping Unit . . . . . . . . . . . . . . . . . . . 27
Figure 14.18: Sulfuric Acid Alkylation Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Chapter 15: Materials of Construction for Refinery Applications
Chapter 16: Refinery Operations and Overview
Figure 16.1: System Flow of a Conversion Refinery . . . . . . . . . . . . . . . . . . . . . . . 7
Figure 16.2: Distillation Tower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Figure 16.3: Catalytic Cracking Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Chapter 17: Failure Analysis in Refineries
Corrosion Control in the Refining Industry
©NACE International 2008
January 2010
1
Corrosion Control in the Refining Industry
List of Tables
Chapter 1: Corrosion and Other Failures
Table 1.1: Corrosives Found in Refining Processes. . . . . . . . . . . . . . . . . . . . . . . . 10
Table 1.2: Galvanic Series of Metals and Alloys in Seawater . . . . . . . . . . . . . . . . 22
Table 1.3: Rate Factors for Alloy Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
Table 1.4: Maximum Temperature for Long-Term Exposure to Air . . . . . . . . . . . 45
Table 1.5: Alloy Systems Subject to SCC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Chapter 2: Crude Distillation and Desalting
Table 2.1: Number of Carbon Atoms vs. Boiling Temperature . . . . . . . . . . . . . . . . 8
Table 2.2: Typical Crude Oil Fractions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Table 2.3: Typical Gravities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Chapter 3: Fluid Catalytic Cracking Units
Table 3.1: Typical FCC Yields. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Table 3.2: FCC Unit Reactor Regenerator and Main Fractionator Damage
Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Table 3.3: Inspection and Control Measures for FCCU Reactor, Regenerator,
and Main Fractionator Damage Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Chapter 4: Cracked Light Ends Recovery Units
Chapter 5: Hydrofluoric Acid Alkylation Units
Chapter 6: Sulfuric Acid Alkylation Units
Table 6.1: Common Corrosion Probe Locations in Sulfuric Acid Alkylation
Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Table 6.2: Common Stream Analyses for H2SO4 Alkylation . . . . . . . . . . . . . . . . 19
Chapter 7: Hydroprocessing Units
Chapter 8: Catalytic Reforming Units
Table 8.1: Volume % of Feed and Product Components . . . . . . . . . . . . . . . . . . . . . 3
Table 8.2: RON of Several Hydrocarbon Compounds. . . . . . . . . . . . . . . . . . . . . . . 4
Chapter 9: Delayed Coking Units
Chapter 10: Amine Treating Units
Table 10.1: Chemical Data on Selected Substances. . . . . . . . . . . . . . . . . . . . . . . . 10
Table 10.2: Chemical Data for Common Amines . . . . . . . . . . . . . . . . . . . . . . . . . 11
Table 10.3: Potential Corrosion Reactions in Amine Units . . . . . . . . . . . . . . . . . . 11
Corrosion Control in the Refining Industry
©NACE International 2008
January 2010
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Chapter 11: Sulfur Recovery Units
Chapter 12: Refinery Injection Systems
Chapter 13: Process Additives and Corrosion Control
Chapter 14: Corrosion Monitoring in Refineries
Table 14.1: Types of Corrosion Monitoring Methods . . . . . . . . . . . . . . . . . . . . . . . 4
Chapter 15: Materials of Construction for Refinery Applications
Table 15.1: Return on Investment Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Table 15.2: U.S. Standards Organizations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Table 15.3: The Refinery Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Table 15.4: Other Refinery Metals and Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Table 15.5: Some Specific Effects of Alloys in Steel . . . . . . . . . . . . . . . . . . . . . . 22
Table 15.6: ASTM Standard Specifications for Refinery Steels . . . . . . . . . . . . . . 24
Table 15.7: Chemical Composition of Principal Stainless Steels . . . . . . . . . . . . . 28
Table 15.8: Chemical Composition of Principal Nickel Alloys . . . . . . . . . . . . . . . 37
Table 15.9: Preheat Temperatures for Refinery Steels. . . . . . . . . . . . . . . . . . . . . . 48
Table 15.10: PWHT Temperatures for Refinery Steels . . . . . . . . . . . . . . . . . . . . . 49
Chapter 16: Refinery Operations and Overview
Table 16.1: Regulations and Standards Related to Refinery Equipment Integrity. . 3
Table 16.2: Summarizes common refinery processes . . . . . . . . . . . . . . . . . . . . . . . 6
Chapter 17: Failure Analysis in Refineries
Corrosion Control in the Refining Industry
©NACE International 2008
January 2010
Corrosion and Other Failures
1-1
Chapter 1:Corrosion and Other
Failures
Objectives
Upon completing this chapter, you will be able to do the following:
•
Become acquainted with the instructor and the other class
participants
•
Develop an understanding of Corrosion Control in the Refining
Industry course objectives and schedule
•
Become familiar with the expectations of the course
•
Discuss and summarize your expectations and reservations
regarding this course
•
Identify and define the two categories of refinery corrosion
•
Identify types of damage in addition to corrosion encountered in
refining equipment
•
Identify the oxidation and reduction reactions taking place in
low-temperature refinery corrosion
•
Differentiate between activation polarization and concentration
polarization
•
Define passivity in metals
•
Describe the relationship between temperature and concentration
increases and the corrosion rate
•
Identify the oxidation and reduction reactions taking place in
high-temperature refinery corrosion
•
Identify the types of compounds that may cause corrosion problems in refineries as well as their sources
•
Identify and discuss types of general and/or localized corrosion
that generate metal loss in refinery equipment
•
Describe techniques that can be used to minimize each type of
general or localized corrosion occurring in refinery equipment
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•
Identify and discuss types of stress corrosion cracking that may
be experienced by refinery equipment as well as techniques that
can be used to prevent them
•
Identify refinery areas susceptible to high-temperature hydrogen
attack and materials that may be used for prevention
•
Identify and discuss metallurgical failures that may take place in
refinery equipment and techniques or materials that may be used
to prevent them
•
Identify and discuss mechanical failures that may occur in refinery equipment and techniques or materials that may be used to
prevent them
•
Discuss additional types of corrosion, such as boiler feed water
corrosion, steam condensate corrosion, cooling water corrosion,
and fuel ash corrosion, and techniques or materials that may be
used to minimize them.
1.1 Introduction
Damage from corrosion and metallurgical/mechanical mechanisms
often leads to failures in refinery equipment, which interrupt
refinery operations and create safety hazards. The existence as well
as the degree of damage is dependent on the particular process
operating conditions and contaminants present in the process
stream. Everyone in the refining industry today, including the
refinery owner, refinery operator, mechanical engineer, metallurgist,
and process engineer, is looking for ways to prevent or minimize the
effects of corrosion. Corrosion control is paramount to the safe and
productive operation of a facility.
Billions of dollars are spent annually on corrosion-related problems
that could have been eliminated or reduced by applying corrosion
fundamentals. Ideally, corrosion concerns should be considered
prior to refinery construction to reduce costs associated with
maintenance, shutdowns, contamination, or loss of valuable
product, and safety and reliability issues. Timely and proper
inspection and maintenance of equipment are also required to
reduce the number of corrosion failures and their accompanying
expenses.
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NACE International defines corrosion as…
…The deterioration of a material, usually a metal, because of a
reaction with its environment.
The definition is very general and recognizes that some forms of
corrosion are not chemical or electrochemical in nature. The
definition also recognizes that materials other than metals may
corrode. These materials include concrete, wood, ceramics, and
plastics. In addition, in some forms of corrosion the properties of the
material as well as the material itself deteriorate. A material may
experience no weight change or visible deterioration yet, due to
property changes promoted by corrosive action, the material may
fail unexpectedly.
Refinery corrosion can be categorized as:
•
Low-temperature corrosion—Occurs at temperatures below
500F (260C) and in the presence of water
•
High-temperature corrosion—Occurs at temperatures above
500F (260C), with no water present.
Within these two categories are many types of corrosion that occur
under very specific combinations of materials and environment/
operating conditions.
Once equipment is placed in process service, it is subject to
operating upset and/or downtime conditions that may cause damage
or deterioration. In refining applications, the material and
environmental condition interactions are quite varied. Many
refineries contain over fifteen different process units, each having its
own combination of numerous corrosive process streams and
temperature and pressure conditions.
Without the presence of corrosion, all refinery equipment will
eventually deteriorate. The deterioration normally occurs very
slowly, unless incorrect or defective materials were initially
installed. Mechanical damage, overloading of structural members,
and over-tightening of bolts represent a large portion of mechanical
failures. Accidental overpressuring or brittle fracture of equipment
may occur in fixed equipment, while fatigue failures are common
with machinery having highly stressed, reciprocating parts.
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Changes in process temperature or pressure, upsets, overfiring of
furnaces to increase throughput, instrument failures, or exposure to
fire often occur within refineries. These conditions can produce
metallurgical failures when changes take place in the microstructure
and/or chemistry of original materials of construction. For example,
furnace tubes can sag or bulge, vessel walls become distorted and
develop cracks and blisters, and piping becomes embrittled. Since
high-temperature operations are usually carried out at high
pressures, metal deterioration may result in serious consequences. In
addition, failures are often accelerated by cyclic changes, including
periodic shutdowns.
1.2 Low-Temperature Refinery
Corrosion
Low-temperature refinery corrosion is also called aqueous
corrosion, wet corrosion, or electrochemical corrosion. It requires
the presence of an aqueous solution, including water even in very
small amounts, or an electrolyte in a hydrocarbon stream. In vapor
streams, low-temperature corrosion is often found where water
condenses.
Types of low-temperature corrosion found in refineries include:
•
Uniform corrosion
•
Galvanic corrosion
•
Pitting
•
Erosion-corrosion
•
Stress corrosion cracking (SCC).
These and other types of low-temperature corrosion mechanisms
prevalent in refineries will be examined as the chapter continues.
1.2.1 Low-Temperature Corrosion Principles
Low-temperature corrosion obeys electrochemical laws but is often
controlled by diffusion processes. Metals corrode through
simultaneous oxidation and reduction reactions. Oxidation reactions
produce electrons and put ions into solution. They occur at anodic
sites on the metal and, as a result, are called anodic reactions. The
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anode of a corrosion cell corrodes. The anodic reaction in every
corrosion process is the oxidation of a metal to its ionic form as
shown below:
M  M+n + ne–
Reduction reactions consume the electrons produced by oxidation
reactions and occur at cathodic sites on the metal. Therefore,
reduction reactions are called cathodic reactions, occurring at the
cathode, which does not corrode. Common cathodic reactions are:
2H+ + 2e–  H2 (gas)
hydrogen evolution
O2 + 4H+ + 4e–  2H2O
oxygen reduction in acid
solutions
oxygen reduction in neutral or
basic solutions
metal ion reduction
metal deposition (plating)
O2 + 2H2O + 4e–  4OH–
M+3 + e–  M+2
M+ + e–  M
Hydrogen evolution and oxygen reduction are among the more
common cathodic reactions. In refinery equipment, bisulfide
reduction is also common. Bisulfide reduction proceeds as follows:
2HS– + 2e– H2 (gas) + 2S–2
The anodic reaction that takes place when iron or steel comes into
contact with water is:
Fe  Fe+2 + 2e–
Since the water contains dissolved oxygen from air, the cathodic
reaction is:
O2 + 2H2O + 4e–  4OH–
The overall corrosion reaction combines the anodic and cathodic
reactions as shown below:
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2Fe + 2H2O + O2  2Fe+2 + 4OH–  2Fe (OH)2
(Fe (OH) 2 = solid ferrous hydroxide)
Ferrous hydroxide precipitates from solution and is oxidized to
ferric hydroxide as follows:
2Fe (OH) 2 + H2O + ½ O2  2Fe (OH) 3 (solid ferric hydroxide)
Ferric hydroxide is commonly known as rust. The rusting of iron in
oxygenated water is a common example of electrochemical
corrosion. See Figure 1.1. In an electrochemical reaction, the more
negative or active ion tends to be oxidized and the more positive or
noble ion tends to be reduced. In Figure 1.1, iron has the more active
potential so it becomes the anode and corrodes. Silver is the nobler
of the two and becomes the cathode.
Electron Flow
Electron Flow
(–) ANODE
(+) CATHODE
IRON
Fe
Fe +2
H2
Fe +2
SILVER
H2
H+
Fe +2
Fe +2
H+
Fe +2
Anode Reaction: Fe
Cathode Reaction: H 2
H+
Ag
H+
Fe +2
H+
Fe +2 + 2e –
2e – + 2H +
Figure 1.1 Electrochemical Corrosion Cell
The reactions shown in Figure 1.1 normally proceed slowly due to a
limited number of hydrogen ions available from the water
dissociation reaction. If a greater number of hydrogen ions are made
available by the addition of acid to the solution, for example, the
corrosion reaction will proceed more rapidly.
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Corrosion usually involves more than just one oxidation and
reduction reaction. When an alloy corrodes, its components go into
solution as their own respective ions. Several cathodic reactions
take place at the same time. The rates of anodic and cathodic
reactions must be equal. Therefore, two or more cathodic reactions
result in greater electron consumption and thereby accelerate the
anodic reaction.
1.2.2 Corrosion Rates and Polarization
The corrosion rate determines whether a material is usable in a
particular service environment. Corrosion rates are measured as
weight loss per unit area and are expressed in mils (0.001 inch) of
penetration per year (mpy). Corrosion rates below about 5 mpy are
generally considered acceptable for long-term service.
Reducing the rate of either the anodic or cathodic reaction or both
can decrease the rate of corrosion. For example, iron will not
corrode in deaerated water because oxygen reduction cannot take
place. Some corrosion inhibitors are formulated to retard the anodic
or cathodic reaction. Other corrosion inhibitors are designed to form
a protective, nonconducting film on the metal surface. Protective
coatings prevent corrosion in a similar manner.
Polarization limits or retards the electrochemical reaction by certain
physical or chemical factors. It is simply a change in potential as the
result of current flow. There are two types of polarization:
•
Activation polarization
•
Concentration polarization.
Activation polarization takes place when the electrochemical
process (corrosion) is controlled by the reaction sequence at the
metal surface. For example, hydrogen ions must be absorbed on the
corroding surface before hydrogen reduction can take place.
Electron transfer must occur next, forming atomic hydrogen. Two
hydrogen atoms then combine to produce hydrogen gas, which
bubbles off the metal surface. If hydrogen reduction is controlled by
the slowest of these reaction steps, corrosion is said to be activation
polarized. Corrosion in concentrated acids is usually controlled by
one or more reaction step at the metal surface.
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Concentration polarization occurs when corrosion is controlled by
diffusion in the corrosive environment. Ions moving in solution to
the anode and cathode limit the corrosion rate. Agitating the fluid
accelerates corrosion. With hydrogen evolution, corrosion is
concentration polarized if hydrogen ion diffusion becomes the ratecontrolling step. Corrosion in very dilute acids typically depends on
ion diffusion. Process changes in refineries will produce different
results depending on the type of polarization that controls the
reactions. For example, lowering flow velocity will decrease
corrosion only if the cathodic reaction is controlled by concentration
polarization.
1.2.3 Passivity
Passivity refers to the increase in corrosion resistance of certain
metals and alloys, resulting from the formation of a protective
surface film. In the passive state, a metal becomes relatively inert,
and the corrosion rate is slow. If the protective film is destroyed, the
corrosion rate increases many thousand times, and the metal is said
to be active. Under certain conditions, some metals, such as
stainless steels and alloys of aluminum, chromium, and titanium,
can become repassivated.
Normally, protective films are stable over a wide range of
conditions, but are damaged or destroyed in highly reducing or
oxidizing environments. Active ions, such as chlorides, can interfere
with the integrity of surface films and lead to various forms of
corrosion in austenitic stainless steels. As a result, refineries are
reluctant to use austenitic stainless steels in aqueous service
environments.
Metals and alloys that form protective oxide films require some
oxygen in the environment to maintain passivity. In refinery service
water there is normally sufficient dissolved oxygen to maintain the
passivity of stainless steel or titanium, but not enough oxygen to
passivate carbon steel. However, chromates have been used as
effective cooling water inhibitors because they readily oxidize and
passivate carbon steel surfaces.
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1.2.4 Temperature and Concentration
Corrosion rates generally increase with increases in temperature.
When corrosion is controlled by the rate of surface reaction at the
anode or cathode, corrosion rates typically double for each 18F
(10C) temperature increase. With diffusion-limited corrosion, the
effect of temperature is not as great. Temperature increases may also
increase the amount of water in liquid hydrocarbon and vapor
streams. As a result, more water is likely to condense out in
downstream distillation towers or in overhead condensing systems.
Therefore, corrosion can occur in equipment that was thought to be
dry.
Concentration increases in the corrosive environment generally
increase corrosion rates. However, corrosion in concentrated acids is
often minimal because water is absent. In refinery streams, the
concentration of a corrosive component in a hydrocarbon stream
must be considered in terms of the amount of water present. For
example, carbon steel is severely attacked by dilute sulfuric acid.
1.2.5 Low-Temperature Conditions
Most corrosion problems in refineries are not caused by the
hydrocarbons being processed, but by various inorganic
compounds, such as:
•
Water
•
Hydrogen sulfide
•
Hydrogen chloride
•
Sulfuric acid
•
Carbon dioxide.
Table 1.1 on page 10 presents a list of corrosives found in many
refining processes. Several of these promote high-temperature
mechanisms as well.
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Table 1.1: Corrosives Found in Refining Processes
Sulfur
Naphthenic Acid
Polythionic Acid
Chlorides
Carbon Dioxide
Ammonia
Cyanides
Present in raw crude. It causes hightemperature sulfidation of metals and
combines with other elements to form
aggressive compounds, such as sulfides,
sulfates, and sulfurous, polythionic, and
sulfuric acids.
A collective name for organic acids
found primarily in crude oils from the
western U.S., and certain Texas, Gulf
Coast, and a few Middle-Eastern oils.
Sulfurous acids formed by the interaction
of sulfides, moisture, and oxygen and
occurring when equipment is shut down.
Present in the form of salts, such as
magnesium chloride and calcium
chloride, originating from crude oil,
catalysts, and cooling water.
Occurs in steam reforming of
hydrocarbon in hydrogen plants and, to
some extent, in catalytic cracking. CO2
combines with moisture to form carbonic
acid.
Nitrogen in feedstocks combines with
hydrogen to form ammonia (or ammonia
is used for neutralization) which, in turn,
may combine with other elements to
form corrosive compounds, such as
ammonium chloride.
Usually generated in the cracking of
high-nitrogen feedstocks. When present,
corrosion rates are likely to increase.
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Hydrogen Chloride Formed
through
hydrolysis
of
magnesium chloride and calcium
chloride, it is found in many overhead
(vapor) streams. On condensation, it
forms highly aggressive hydrochloric
acid.
Hydrogen Sulfide
Present in sour crude oils and gases.
Formed by decomposition of organic
sulfur compounds and/or reaction with
hydrogen in some processing units.
Hydrofluoric Acid
Sulfuric Acid
Hydrogen
Phenols
Oxygen
Carbon
Used as a catalyst in alkylation plants.
Used as a catalyst in alkylation plants
and is formed in some process streams
containing sulfur trioxide, water, and
oxygen.
In itself not corrosive, but can lead to
blistering and embrittlement of steel.
Also, it combines with other elements to
produce corrosive compounds.
Found primarily in sour water strippers.
Originates in crude, aerated water, or
packing gland leaks. Oxygen in the air
used with fuel in furnace combustion and
FCC regeneration results in hightemperature environments, which cause
oxidation and scaling of metal surfaces
of under-alloyed materials.
Not corrosive, but at high temperatures
results in carburization that causes
embrittlement or reduced corrosion
resistance in some alloys.
Crude oil contaminants are the major cause of low-temperature
corrosion in refineries. Most are present in crude oil as it is
produced. Some contaminants are removed during preliminary
treatment in the oil fields. The remaining contaminants end up in
refinery tankage, along with contaminants picked up in pipelines or
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marine tankers. Most of the actual corrosives are formed during
initial refinery operations. For example, highly corrosive
hydrochloric acid evolves in crude oil furnaces from calcium and
magnesium chlorides.
Water is found in all crude oils and is difficult to remove completely.
It is not only an electrolyte, but also hydrolyzes some inorganic
chlorides to hydrogen chloride. Rapid corrosion may take place in
the presence of water. The rate of corrosion is accelerated by the
velocity or the acidity of the water. In general, whenever equipment
can be kept dry, corrosion problems will be minimized.
The addition of air can be especially detrimental. Water readily
dissolves a small amount of oxygen from the atmosphere into
solution, and this may become highly corrosive. For example, the
amount of moisture and air drawn into storage tanks during normal
breathing, as a result of temperature changes and transfers, is
directly related to the amount of tank corrosion experienced.
Crude and heavy oils form a somewhat protective oil film on the
working areas of a tank shell. Corrosion in tanks handling these
stocks is generally limited to the top shell ring and the underside of
the roof where protective oil films are minimal if they are not
normally in contact with the oil. Tank bottom corrosion occurs
mostly with crude oil tankage and is caused by separated water and
salt entrained in the crude oil. A layer of water settles out on the
tank bottom and becomes highly corrosive.
Tanks that handle gasoline and other light stocks primarily
experience corrosion at the middle shell rings because these see
more wetting and drying cycles than other areas. Light stocks do not
form protective oil films. The rate of corrosion is proportional to the
water and air content of light stocks, and chloride and hydrogen
sulfide contamination accelerates attack.
Refinery equipment can be exposed to moisture and air, which can
be pulled into the suction side of pumps if seals or connections are
not tight. Air and moisture can also be dissolved in hydrocarbons
that were stored in tanks where air and moisture were accessible. In
general, air contamination of hydrocarbon streams is more
detrimental with regard to fouling than corrosion.
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Hydrogen sulfide is present in sour crude oils and gases handled by
most refineries. It is also formed by decomposition of organic sulfur
compounds during crude processing at high temperatures. The
various corrosion and damage mechanisms related to hydrogen
sulfide will be examined as the chapter proceeds.
1.3 High-Temperature Refinery
Corrosion
High-temperature corrosion is also referred to as dry corrosion or
direct chemical combination. It occurs above the environmental dew
point and is normally associated with high temperatures. Gases are
the typical corrosive agents.
1.3.1 High-Temperature Corrosion Principles
As with low-temperature corrosion, high-temperature refinery
corrosion is an electrochemical process consisting of two or more
partial (oxidation and reduction) reactions. When metal is exposed
to air, it is oxidized to an ion at the metal/scale interface according
to the following equation:
M  M+n + ne–
At the same time, oxygen is reduced at the scale surface as shown in
the equation below:
½ O2 + 2e–  O–2
The overall corrosion reaction is obtained by combining the
oxidation and reduction reactions to form a metal oxide as follows:
M + ½ O2  MO
Nearly all metals will react with oxygen at high temperatures to
form an oxide scale. Metal oxides serve a number of functions
similar to those in low-temperature corrosion, including:
•
They are able to conduct ions.
•
They are able to conduct electrons.
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•
Corrosion and Other Failures
They serve as an electrode for oxygen reduction.
The electronic conductivity of most oxides is much greater than
their ionic conductivity. Therefore, the reaction rate depends on the
diffusion rates of either the metal ions (outward) or the oxygen ions
(inward), or both. Temperature, temperature fluctuations, the
integrity of the oxide layer, and the presence of other gases in the
atmosphere influence the diffusion of the metal and oxygen ions.
Oxidation can be controlled if the diffusion rates can be reduced in
some fashion. However, no practical means of achieving this have
been found. Rather, oxidation resistance is improved by alloying the
base metal so more protective oxides are formed in the scale.
Scale consists of several different, stable compounds. For example,
when carbon steel is oxidized, layers of FeO, Fe3O4, and Fe2O3 are
formed in sequence. The layer containing the highest proportion of
oxygen (Fe2O3) is found at the outer scale surface. The layer with
the highest proportion of iron (FeO) is located at the steel/scale
interface. The thickness of each oxide layer depends on the rates of
ion diffusion through the layer.
Oxide scales grow primarily at the scale surface by outward
diffusion of metal ions. It is also thought that some scales grow by
dissociation of inner oxide layers, sending metal ions outward and
oxygen molecules inward. These scales grow both at the metal/scale
interface and at the scale surface. In reality, scale formation is quite
complex, being influenced by a number of factors, including:
•
Dissolution of oxygen atoms in some metals
•
Low melting points and high volatility of some oxides
•
The existence of grain boundaries in the metal and the scale.
Since scale usually adheres to metal surfaces, the rate of hightemperature corrosion is measured and expressed in terms of weight
gain per unit area. High-temperature corrosion of common refinery
metals obeys one of two rate laws:
•
Linear Rate Law
•
Parabolic Rate Law.
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The particular rate law followed by high-temperature corrosion
depends on whether the metal oxide layer is protective or
nonprotective.
1.3.2 Linear Rate Law
The Linear Rate Law applies when a nonprotective oxide layer
allows continuous, steady access of oxygen to the metal. Cracked or
porous scales are formed, which do not prevent diffusion of metal or
oxygen ions. The rate of growth of the oxide layer is independent of
thickness, and the thickness of the layer increases in a linear manner
with time. See Figure 1.2.
Figure 1.2 Linear Rate Law of High-Temperature Corrosion
At high temperatures and over long periods of time, a metal will
completely oxidize because the corrosion rate never slows down.
Linear oxidation may occur in an environment where the oxygen
content is very low. It may also occur as a result of cracking and
spalling of the oxide layer. When cracked, the oxide layer is
nonprotective and the oxidation rate becomes very high for a short
period of time. The rate gradually reduces as the layer rebuilds. If
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the film thickness is relatively small, the measured oxidation rate
appears constant.
At the beginning of the high-temperature corrosion process,
oxidation rarely follows the Linear Rate Law. A brief initial period
in which the corrosion rate changes is followed by a period in which
the rate is constant. Two oxide layers with dissimilar properties
result. The first layer forms during the initial period as a thin,
continuous film adjacent to the metal. The thickening rate is
controlled by diffusion through the film so that the rate slows as the
film thickens.
At some point during oxidation, the oxide layer changes from a thin,
continuous film to a nonprotective porous scale. As mentioned
previously, the scale may crack and spall. Oxidation follows the
Linear Rate Law when the thickening rate of the porous layer equals
the rate at which it cracks. The thin inner layer remains a constant
thickness to give the oxidation rate the appearance that it is constant.
Metals that oxidize in this fashion and obey the Linear Rate Law
include:
•
Molybdenum
•
Titanium
•
Zirconium
•
Tungsten.
1.3.3 Parabolic Rate Law
The Parabolic Rate Law applies when formation of a protective
oxide layer provides a continuous barrier between oxygen and
metal, inhibiting further oxidation. The protection is directly
proportional to the thickness of the oxide layer. See Figure 1.3.
Parabolic kinetics yield a straight line when weight gain data are
squared and plotted versus exposure time.
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Figure 1.3 Parabolic Rate Law of High-Temperature Corrosion
The equation shown in Figure 1.3 predicts a rate of oxidation that is
initially high, but continuously decreases according to a parabolic
function.
Parabolic scaling rates are controlled by ion diffusion through a
scale layer, which is continuously increasing in thickness. Most
metals and alloys, including carbon steel and low-alloy steels, obey
the Parabolic Rate Law. During the early stages of film formation,
the growth rate is controlled by surface reactions, which occur first
at the metal/oxygen interface and later at the metal/oxide and oxide/
oxygen interfaces as the film increases in thickness. When the film
becomes appreciably thicker, the controlling factor in the growth
rate of the oxide layer becomes the diffusion of metal or oxygen
through the oxide layer.
1.3.4 High-Temperature Conditions
High-temperature corrosion problems in refineries may lead to
equipment failures, which can have serious consequences because
high-temperature processes usually involve high pressures. In
addition, with hydrocarbon streams, there is always the danger of
fire if leaks or ruptures occur.
High-temperature corrosion is related to the nature of the scale that
is formed. For example, uniform scale reflects uniform attack while
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pitting occurs where scale has been locally damaged. Intergranular
attack occurs when grain boundaries between the grains of a metal’s
structure corrode in preference to the grains. Since many refinery
processes at elevated temperatures involve vapor or mixed vapor/
liquid streams at high flow velocities, high-temperature corrosion
often results in fatigue, erosion, and cavitation damage.
Carbon steel may be used in high-temperature conditions without
excessive scaling up to a temperature of about 1050F (565C).
Above this temperature, various alloys must be used to increase
oxidation resistance and to provide adequate mechanical properties.
Most high-temperature refinery corrosion is caused by various
sulfur compounds, which are found in many crude oils and refining
unit charge stocks. Most of the sulfur compounds are organic
compounds, but some crude oils contain significant amounts of
dissolved hydrogen sulfide. Most sulfur compounds will decompose
or combine with hydrogen in various process atmospheres to form
hydrogen sulfide. In addition, hydrogen sulfide dissolved in crude
oil will be released when the crude is heated.
At temperatures above 450F (232C), hydrogen sulfide will react
with iron to form iron sulfide as indicated in the following equation:
Fe + H2S  FES + H2
The conversion of iron to iron sulfide (FES), which is called H2S
corrosion, occurs more rapidly at higher temperatures. Since
hydrogen is involved in the reaction, hydrogen partial pressure
affects the corrosion rate as well. Hydrogen may accelerate or retard
corrosion, depending on which of several FES species is present.
Over the years, extensive research has been done to establish the
mechanisms of various forms of high-temperature sulfidic
corrosion. Fortunately, corrosion rate correlations are available so
that equipment life can be reliably predicted.
Naphthenic acids may also cause problems at high temperatures.
They attack metals at high temperatures, but do not form a
protective scale. Damage to carbon steels, low-alloy steels, and
ferritic or martensitic stainless steels containing less than 12%
chromium appears as localized areas of uniform attack. However, on
austenitic stainless steels, such as type 304 and type 316, naphthenic
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acids cause pitting due to a breakdown of the passive oxide film,
which normally protects these alloys from corrosion.
1.4 Corrosion/Failure Mechanisms
The remainder of this chapter is devoted to examining six major
classifications of damage and damage mechanisms common to
refineries, which are:
•
Metal loss due to general and/or localized corrosion
•
Stress corrosion cracking (SCC)
•
High-temperature hydrogen attack (HTHA)
•
Metallurgical failures
•
Mechanical failures
•
Other forms of corrosion.
1.4.1 Metal Loss—General and/or Localized
Corrosion
General and/or localized types of corrosion causing metal loss
include:
•
Galvanic corrosion
•
Pitting
•
Crevice corrosion
•
Intergranular attack
•
Erosion-corrosion
•
Hydrogen chloride
•
Ammonium bisulfide (NH4HS)
•
Carbon dioxide (CO2)
•
Process chemicals
•
Organic chlorides
•
Aluminum chloride
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•
Sulfuric acid
•
Hydrofluoric acid
•
Phosphoric acid
•
Phenol (carbolic acid)
•
Amine
•
Atmospheric (external) corrosion
•
Corrosion under insulation (CUI)
•
High-temperature sulfidation (with and without hydrogen)
•
Naphthenic acid corrosion
•
Oxidation.
1.4.1.1 Galvanic Corrosion
Galvanic corrosion, a form of wet corrosion, occurs when two
metals or alloys are coupled (joined electrically) in the presence of
an electrolyte. See Figure 1.4.
Figure 1.4 Dry Cell Battery - A typical Example of Galvanic (Electrochemical)
Corrosion
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Shown above are the four essential elements that must be present for
galvanic corrosion to occur:
•
Electrolyte—Moist ammonium chloride and zinc chloride,
which is the liquid or corrosive medium that conducts electricity.
•
Anode—Negative electrode (zinc case), which corresponds to
the anode in a corrosion cell.
•
Cathode—Positive electrode (carbon [graphite]), which corresponds to the cathode in a corrosion cell.
•
Metallic pathway—Surplus electrons at the anode flow through
the metallic pathway to the cathode.
The tendency of a metal to corrode in a galvanic cell is determined
by its position in the galvanic series of metals and alloys. See
Table 1.2 on page 22. The ranking is based on galvanic corrosion
tests and electrical potential measurements in seawater. Metals near
the top of the table become anodic or active and corrode when in
contact with a metal listed near the bottom of the table. The further
apart two metals are in the series, the more likely the less noble
metal in the couple will experience galvanic corrosion.
Certain alloys, such as austenitic stainless steels are shown in two
positions depending on whether they are in the active or passive
state. The dual nature of stainless steels is related to their ability to
form protective films (passivity) in the presence of oxygen or other
oxidizing agents, such as nitric acid or carbonic acid. If the
protective film is destroyed, these alloys will be in the active
condition and corrode rapidly in the presence of hydrochloric,
hydrofluoric, or other oxygen-free acids. To select the correct
stainless steel for an application, the engineer must determine
whether it will be in the passive or active state.
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Table 1.2: Galvanic Series of Metals and Alloys in Seawater
Corroded End—Anodic—More Active
Magnesium
Magnesium alloys
Zinc
Aluminum
Aluminum alloys
Steel
Cast iron
Type 410 stainless steel (active state)
Ni-Resist
Type 304 stainless steel (active state)
Type 316 stainless steel (active state)
Lead
Tin
Nickel (active state)
Brass
Copper
Bronze
Copper-Nickel
Monel
Nickel (passive state)
Type 410 stainless steel (passive state)
Type 304 stainless steel (passive state)
Type 316 stainless steel (passive state)
Titanium
Graphite
Gold
Platinum
Protected End—Cathodic—Less Active
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The rate of corrosion resulting from galvanic action depends upon
the relative exposed areas of the two metals in contact. For example,
if there is a large ratio of anode area to cathode area, the cathode
will effectively be protected and may not corrode at all. However, a
small anode area when coupled with a large cathode area will
corrode rapidly.
Small anode, large cathode areas are often seen in refinery water
systems. Consider the case of a steel water pipe coupled to a brass
fitting. From the galvanic series, it can be seen that the steel is more
active than the brass. The steel is the anode and the brass is the
cathode. Near the point of contact, the steel will corrode faster than
normal, while the brass will corrode more slowly. The area of steel
affected and the intensity of corrosion will depend upon the relative
size of the brass component, geometry of the coupled parts,
availability of dissolved oxygen, pH, and the resistivity of the water.
Depending on the influence of these variables, the steel pipe
corrosion pattern can range from localized knife-like attack to
broad, general corrosion.
Galvanic corrosion is not limited to cells in which totally dissimilar
metals are in contact while exposed to an electrolyte. Sometimes
differences in composition or surface condition of otherwise similar
metals result in galvanic corrosion cells as evidenced by the
following examples:
•
A weld or heat-affected zone may be anodic to the parent metals,
establishing a small anodic area to large cathodic area relationship.
•
New steel electrically connected to old steel tends to corrode
more rapidly than the old steel to which it is connected.
•
Steel pipe connected to copper pipe or tubing will corrode.
•
A steel propeller shaft operating in a bronze bearing will
corrode.
Galvanic attack can be minimized or prevented by remembering:
•
Corrosion is more severe near the junction of two dissimilar
metals, with attack decreasing with increasing distance from that
point.
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•
The severity of corrosion is related to the electrical conductivity
of the solution. Galvanic corrosion does not occur in hydrocarbon or vapor systems unless free water is present.
•
The area of the more anodic metal should be as large as possible
compared to that of the cathodic metal.
•
Dissimilar metals should be electrically insulated wherever
practical. If insulation is not complete, corrosion can be accelerated.
•
Painting or coating, when used, must be applied to the entire
assembly or at least the less active, cathodic member. If only the
anode is coated, breaks in the coating can cause the exposed area
to corrode very rapidly.
•
Corrosion inhibitors may be used to reduce galvanic effects in
many refinery aqueous environments.
•
Sacrificial anodes along with paints/coatings may be used to
reduce galvanic effects.
1.4.1.2 Pitting
Pitting is a highly localized corrosion in the form of small holes or
pits. It can occur in isolated locations or be so concentrated it looks
like uniform attack. Pitting can be difficult to detect because it has a
tendency to undercut the metal surface and is usually covered by
corrosion product. Equipment failures are usually in the form of
perforations at one or more points, with only minor overall damage.
Pitting usually occurs under stagnant flow conditions in the
presence of chloride ions. Chloride ions are relatively small and
mobile enough to penetrate protective films, scale, or corrosion
products. Oxidation of the metal takes place within the pit, while the
cathodic reaction takes place on adjacent surfaces. As a result, an
excess of positive ions is produced within the pit, and the chloride
ions migrate toward them to maintain electrical neutrality.
Subsequent hydrolysis lowers the pH of the solution within the pit,
accelerating metal oxidation.
Pitting is initiated at surface defects, emerging inclusions, or grain
boundaries of the metal. In refineries, pitting has mostly been a
problem with martensitic, ferritic, and austenitic stainless steels.
Alloying with molybdenum reduces pitting in these stainless steels.
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Metals and alloys that pit during corrosion testing should not be
used to construct process equipment.
1.4.1.3 Crevice Corrosion
Crevice corrosion is a localized corrosion associated with stagnant
solutions in crevices, such as under bolt heads, gaskets, and
washers, and in threaded and lap joints. It also occurs under wet
packing or insulation, in rolled tube-to-tubesheet joints, and under
corrosion products. When occurring under corrosion products,
crevice corrosion is also referred to as underdeposit attack. Stainless
steels are particularly susceptible to crevice corrosion in hot
seawater environments. In refineries, crevice corrosion of carbon
steel is seen under various deposits and at gasket connections.
Crevice corrosion occurs when a crevice is wide enough to allow
liquid to enter and narrow enough to maintain a stagnant condition.
Therefore, crevice corrosion is typically limited to openings less
than a few mils wide. The mechanism for crevice corrosion is
similar to that of pitting corrosion, with the crevice acting as a
relatively large pit. Crevice corrosion is most severe in high chloride
environments.
Crevice corrosion can be avoided by:
•
Designing equipment for proper drainage during downtime
•
Minimizing solids deposition with frequent cleaning or
bypassing equipment, if necessary, to keep a unit on stream
•
Welding connections rather than flanging or bolting
•
Removing wet packing from critical equipment during long
shutdowns
•
Specifying low-chloride insulation and keeping it dry with
proper wrapping and caulking
•
Hydrotesting tube rolls for tightness prior to seal welding.
1.4.1.4 Intergranular Attack
Intergranular attack is highly localized corrosion at and adjacent to
the grain boundaries in a metal’s structure while the grains remain
relatively free from attack. Since little corrosion takes place on the
grains, the alloy disintegrates by grain separation. The grains fall
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out. Intergranular attack is caused by the corrosive action of a
specific chemical environment on the metal grain boundaries that
are susceptible to attack from impurities. The enrichment or
depletion of one of the alloying elements at grain boundaries may
also cause attack.
Many alloys are susceptible to intergranular corrosion in specific
environments. However, intergranular corrosion is most prevalent in
the 300-series austenitic stainless steels. With austenitic stainless
steels, intergranular attack is caused by depletion of chromium
resulting from sensitization.
When a stainless steel has a carbon content above 0.03%, and the
alloy is held in or cooled slowly through the temperature range of
700F to 1500F (371C to 816C), chromium and carbon are
removed from solid solution and form chromium-carbides along the
grain boundaries. The result is metal with reduced chromium
content in the area adjacent to the grain boundaries. The chromiumdepleted zone near the grain boundary is corroded because it does
not contain sufficient chromium to resist attack in corrosive
environments. Sensitization can happen during welding or while
equipment is at elevated temperatures.
Intergranular attack can be minimized or prevented by:
•
Specifying low-carbon grades, such as type 304L, type 316L, or
type 317L, which contain insufficient carbon for chromium carbide formation
•
Using chemically stabilized grades, such as type 321 (titaniumbearing) and type 347 (niobium), in which the alloying elements
tie up the carbon
•
Solution annealing the stainless steel by heating to 2000F
(1093C) followed by water quenching to redissolve any precipitated chromium carbide and uniformly distribute chromium
within the microstructure of the metal.
1.4.1.5 Erosion-Corrosion
Erosion-corrosion is an acceleration in the corrosion rate due to the
relative movement of the corrosive fluid with respect to the metal.
Abrasion and mechanical wear increase the corrosive action.
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Damage is in the form of grooves, gullies, elongated holes, and
valleys, which normally form in the same direction.
Erosion-corrosion occurs when protective surface films are
damaged or worn away, continuously exposing fresh metal to
corrosion. Alloys of aluminum, chromium steels, and stainless
steels are especially subject to erosion-corrosion because they
depend on surface film for their corrosion resistance. Areas
susceptible to erosion-corrosion include:
•
Piping bends, elbows, and tees
•
Pump cases and impellers
•
Compressor blades
•
Valve internals
•
Agitators
•
Baffles
•
Thermowells
•
Orifice plates.
In general, any increase in velocity will increase erosion-corrosion,
especially if suspended solids are involved. Often an abrupt critical
velocity is associated with this type of corrosion. Above the critical
velocity, corrosion will be severe. Below the critical velocity,
corrosion will proceed more slowly. For example, flow turbulence at
the inlet of heat exchanger tubes results in rapid corrosion of the
first several inches of tubing where the velocity is greater.
Erosion-corrosion caused by droplets of liquid suspended in a vapor
stream is a real problem in refinery applications. This type of
erosion-corrosion, called impingement corrosion, is caused by water
droplets containing dissolved hydrogen sulfide and hydrochloric
acid moving through equipment when vapor velocities exceed 25 ft/
s (8 m/s).
Erosion-corrosion can be minimized by:
•
Increasing metal thickness to provide greater corrosion allowance
•
Installing sacrificial impingement baffles
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Corrosion and Other Failures
•
Streamlining bends and removing obstructions to smooth flow
and using larger diameter pipe and fittings
•
Installing protective ferrules in tube inlet ends of heat exchanger
bundles
•
Regularly rotating tube bundles to distribute impingement damage and maximize bundle life
•
Installing a corrosion-resistant lining in corroded areas
•
Using titanium or other alloy heat exchanger tubes, which are
highly resistant to impingement corrosion.
1.4.1.6 Hydrogen Chloride
Chloride salts are found in most production wells, either dissolved
in water emulsified in the crude oil or as suspended solids. Salts also
originate from salt water injected for secondary recovery or from
seawater ballast in marine tankers. The amount of salt contained in
the emulsified water may range from 10 pounds to 250 pounds per
thousand barrels of crude oil. The salt typically contains 75%
sodium chloride, 15% magnesium chloride, and 10% calcium
chloride.
Hydrogen chloride corrosion is caused by the presence of hydrogen
chloride. Hydrogen chloride evolves from heating magnesium
chloride and calcium chloride to above 300F (149C). Sodium
chloride is essentially stable up to about 800F (426C).
Hydrogen chloride evolution occurs primarily in the crude preheat
furnace. Dry hydrogen chloride is not corrosive to carbon or lowalloy steel, especially when large amounts of hydrocarbon vapor or
liquid are present. However, when steam is added to the bottom of
the crude tower to facilitate the distillation process, dilute
hydrochloric acid is produced. The hydrochloric acid can cause
severe corrosion in carbon steel equipment at temperatures below
the initial water dew point. The corrosion rate increases with a
decrease in water pH.
The following techniques are used to minimize hydrogen chloride
corrosion:
•
Injecting a neutralizer to maintain the water pH between 5 and 6
•
Using filming amine inhibitors
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•
Changing materials of construction, i.e., replacing carbon steel
tubes with titanium tubes or lining equipment with Monel (70%
Ni, 30% Cu)
•
Eliminating brine from crude oil by proper tank settling and
desalting
•
Injecting dilute fresh caustic into desalted crude to react with any
magnesium chloride and calcium chloride that may still form
hydrogen chloride in the crude feed furnace.
1.4.1.7 Ammonium Bisulfide (NH4HS)
Ammonium bisulfide (NH4HS) is a strong corrosive agent formed
during hydrotreating and hydrocracking of hydrocarbons containing
organic nitrogen and sulfur compounds. It can cause serious
corrosion of carbon steel. High turbulence and velocity can
accelerate this type of corrosion.
A number of alloys, such as Monel (70% Ni, 30% Cu), Incoloy 800,
Incoloy 825, and Alloy 20, and duplex stainless steels have been
used successfully to combat NH4HS corrosion in hydroprocessing
cold-end equipment. Titanium and other alloys are used to prevent
NH4HS corrosion in overhead condenser tubes in sour water
stripping units.
NH4HS will also rapidly attack admiralty brass tubes. In some
applications, admiralty brass tubes have been known to last for only
30 days. If process water has a pH value above 8, carbon steel tubes
are normally not corroded by NH4HS because a protective iron
sulfide film forms on all metal surfaces. However, in service
conditions of high velocity and turbulence, the protective film can
be eroded, resulting in rapid corrosion of the carbon steel.
1.4.1.8 Carbon Dioxide
Carbon dioxide (CO2) is a corrosive found in refinery steam
condensate systems, hydrogen plants, and in the vapor recovery
section of catalytic cracking units. Carbonates remaining in boiler
feed water decompose at elevated temperatures to form CO2,
oxides, and hydroxides. The CO2 goes overhead with the steam. In
the vapor phase, no accelerated corrosion occurs but, when the
steam condenses, CO2 dissolves in the condensate, resulting in rapid
acid corrosion of condensate piping and equipment.
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Corrosion caused by CO2 is mitigated by using:
•
An improved boiler feed water treatment to prevent carbonates
and bicarbonates from entering the boiler
•
Neutralizing amines, which condense with the condensate and
react with the CO2
•
Filming amines, which can be added to the feed water or directly
into the steam to inhibit CO2 formation.
1.4.1.9 Process Chemicals
Process chemicals can cause severe corrosion in refineries. They
include:
•
Hydrogen chloride, which is stripped off reformer catalyst by
moisture in the feed
•
Caustic and other neutralizers, which are added to control acid
corrosion
•
Filming amine corrosion inhibitors, which are very corrosive if
injected undiluted into a hot vapor stream
•
Solvents, which are used in treating and gas-scrubbing
operations.
1.4.1.10 Organic Chlorides
Organic chlorides that contaminate feedstocks produce various
amounts of hydrogen chloride at elevated temperatures. Some
operators use organic chloride solvents to remove wax deposits.
These solvents are also used exclusively for metal degreasing
operations within and out of the refinery. Often, spent solvent is
discarded with slop oil and later mixed with crude oil charged to the
crude unit.
Contaminated crude oils have been found to contain as much as
7000 ppm chlorinated hydrocarbons. The contaminated crude oils
cause severe corrosion in the overhead system of distillation towers
and affect downstream reformer operations. Problems in reformers
include runaway cracking, rapid coke buildup on the catalyst, and
increased corrosion in the fractionator overhead systems. If
contaminated crude oil must be run off, it is recommended to blend
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it slowly into uncontaminated crude oil so that the organic chloride
content of the charge is below 1 ppm to 2 ppm.
Organic chlorides also indirectly cause corrosion problems. For
example, organic chlorides are routinely used to regenerate reformer
catalyst, but if excess moisture is present in the naphtha feed,
hydrogen chloride tends to be stripped off the catalyst. The presence
of hydrogen chloride increases corrosion in reformers as well as in
desulfurizer sections, which use hydrogen makeup gas produced in
reformers.
1.4.1.11 Aluminum Chloride
Aluminum chloride, which is used as a catalyst in refining
processes, hydrolyzes in the presence of water to form hydrochloric
acid. Hydrochloric acid is highly corrosive. As long as aluminum
chloride is kept dry, it in itself is not corrosive.
To control corrosion in the presence of aluminum chloride, the
feedstock is dried in calcium chloride (CaCl2) dryers. In addition,
during shutdowns equipment should be opened for the shortest
possible time and, on closing, should be dried with hot air.
Equipment exposed to hydrochloric acid requires extensive lining
with nickel alloys.
1.4.1.12 Sulfuric Acid
Sulfuric acid, used as a catalyst in alkylation units and in the
regeneration process for demineralized water trains, does not
usually corrode carbon steel at acid concentrations above 85%, at
temperatures below 100F (37.8C), and at velocities under 2 ft/s
(0.6 m/s). However, attack in the form of erosion-corrosion will
occur at sites of high turbulence. In piping systems handling
concentrated sulfuric acid, pipe erosion is often seen around transfer
pumps where hydraulic design has not addressed turbulence.
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Corrosion of Steel by
Sulfuric Acid
Temp, 80-150 F (27-65 C)
Flange Quality
Specification
Carbon
0.25%Max.
Maganese
0.30-.60%
Phosphorus
0.05%Max.
Sulfur
0.05%Max.
3.7
2.5
1.2
(65
C)
(48
C)
(38
C)
(27
C)
Corrosion Rate (mm per year
Steel Completely Immersed Acid Not
Stirred Loss as Inches Penetration
Per Year
0.25
Figure 1.5 Corrosion of Steel by Strong Sulfuric Acid as a Function of Temperature
and Concentration
The curves represent corrosion rates of 5 mpy, 20 mpy, 50 mpy, and
200 mpy.
The corrosion of steel by strong sulfuric acid is complicated because
of the peculiar dip in the curves in the vicinity of 101% acid. The
narrowness of this range means that the acid must be carefully
analyzed to reliably predict corrosion. The dips or increased attack
around 85% are more gradual and less difficult to establish.
Contaminated acid can behave very differently than pure acid.
In low-concentration situations, equipment may require selective
lining with alloys, such as alloy 20, Hastelloy C-276, or B-2. Carbon
steel valves typically require alloy 20 trim because even slight
sulfuric acid attack of the carbon steel seating surfaces will cause
leakage.
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1.4.1.13 Hydrofluoric Acid
Hydrofluoric acid, used as a catalyst in some alkylation units instead
of sulfuric acid, is generally less corrosive than hydrochloric acid
because it passivates most metals by forming protective fluoride
films. Carbon steel can be used for vessels, piping, and valve bodies
in hydrofluoric acid alkylation units as long as feedstocks are kept
dry. Carbon steel welds should be postweld heat treated. Alloys are
used selectively at locations where corrosion of carbon steel is
expected.
Most corrosion problems in hydrofluoric acid alkylation units occur
after shutdowns because pockets of water have been left in the
equipment. The water originates with the neutralization and
washing operations, which are required for personnel safety prior to
opening equipment for inspection and maintenance. All equipment
must be thoroughly dried by draining all low spots and by
circulating hydrocarbon prior to introducing hydrofluoric acid
catalyst. Good welding and threading practices should be followed
because hydrofluoric acid can find the smallest holes in welded and
threaded connections. Flanged connections must also be carefully
made to avoid flange gasket leakage.
1.4.1.14 Phosphoric Acid
Phosphoric acid is sometimes used as a biological nutrient in
refinery process water treatment plants. Its ability to initiate
corrosion is dependent on the methods of manufacture and the
impurities present in the finished product. Fluorides, chlorides, and
sulfuric acids are the main impurities found in the manufacturing
process and in some marketed acids. Small amounts of hydrofluoric
acid in phosphoric acid affect the corrosion resistance of highsilicon irons, austenitic stainless steels without molybdenum, and
tantalum.
Type 316 stainless steel and alloy 20 are two of the most widely
used alloys for handling phosphoric acid. They show little attack in
acid concentrations up to 85% and temperatures up to boiling. Lead
and its alloys are also used at temperatures up to 200F (93C) and
concentrations up to 80% for pure acid. Lead forms an insoluble
phosphate that provides protection to the metal surface. High-silicon
irons, glass, and stoneware provide good resistance to pure
phosphoric acid. High nickel-molybdenum alloys also exhibit good
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resistance to pure phosphoric acid, but are attacked when aerated
and when oxidizing impurities are present.
Copper and high-copper alloys are not widely used in phosphoric
acid service. Aluminum, cast iron, steel, brass, and the ferritic and
martensitic stainless steels exhibit poor corrosion resistance to
phosphoric acid.
1.4.1.15 Phenol (Carbolic Acid)
Phenol or carbolic acid is used in refinery operations to convert
heavy, waxy distillates into premium-grade lubrication oils. Carbon
steel is not subject to corrosion from phenol in the treating section,
where feed is contacted with phenol at temperatures below 250F
(121C). In addition, carbon steel suffers few corrosion problems in
the raffinate recovery section, where phenol is separated from the
treated oil or raffinate. However, in the recovery section, where
spent phenol is separated from the extract by vaporization,
equipment may exhibit varying degrees of corrosion during
different periods of operation.
Both carbon steel and type 304 stainless steel will corrode rapidly in
phenol service at temperatures above 450F (232C). Type 316
stainless steel or Hastelloy C-276 may be used to combat corrosion.
1.4.1.16 Amines
Amines used in gas treating units are sources of refinery corrosion
problems. The amine itself does not cause the corrosion, but
dissolved H2S or CO2, amine degradation products, and heat-stable
salts are the culprits. Corrosion is generally most severe in systems
removing only CO2 and least severe in systems removing only H2S.
Corrosion is normally traced to faulty plant design, poor operating
practices, and/or solution contamination. Locations most affected
are those where acid gases are desorbed or removed from aminerich solutions. Temperatures and flow turbulence are the highest in
these locations, which include the regenerator reboiler and the
regenerator. Corrosion can also be a significant problem on the richamine side of the lean/rich exchangers, in amine solution pumps,
and in reclaimers. Hydrogen blistering, hydrogen-induced cracking,
and stress corrosion cracking may be problems in amine systems.
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Except for the overhead system, the standard material of
construction for amine gas treating equipment is carbon steel.
Welds should be postweld heat-treated to resist stress corrosion
cracking. Pitting and groove-type corrosion of carbon steel reboiler
tubes may require a change to type 304 or type 316 stainless steel.
In general, copper alloys are not used in amine units.
1.4.1.17 Atmospheric (External) Corrosion
Atmospheric corrosion, often in the form of crevice corrosion, is
mostly a problem in refineries located in coastal zones. However,
carbon steel and low-alloy equipment will experience a certain
amount of corrosion when air and moisture are present. Relative
humidity would have to be less than 60% to have essentially no
corrosion.
The normal rate of atmospheric corrosion ranges from 1 mpy to 10
mpy (0.025 mm/y to 0.25 mm/y), but may be as high as 50 mpy (1.2
mm/y) depending on location and time of year. Equipment located
near boiler or furnace stacks will corrode fairly rapidly because
stack gas—sulfur dioxide and sulfur trioxide—dissolve in moisture
present on metal surfaces to form acids. Chlorides, H2S, fly ash,
and chemical dusts in the atmosphere accelerate corrosion.
Protective coatings or paints, which provide a protective barrier, are
the best methods for stopping atmospheric corrosion. Galvanized
steel can also be used to improve service life, especially in areas
where personnel safety is involved, such as ladders, railings, and
flooring.
In coastal locations, special precautions need to be taken to deal
with the relatively high salt content of airborne mist. Zinc-rich
primer paints should be used on carbon and low-alloy steels. These
should be topcoated with maintenance-type epoxy coatings.
Stainless steel equipment should also be considered for coating at
coastal locations to prevent pitting or stress corrosion cracking.
However, coatings containing metallic aluminum or zinc powder
should not be used on austenitic stainless steels due to the danger of
liquid metal embrittlement. Liquid metal embrittlement poses a
problem if welding is conducted or if equipment is exposed to fire.
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1.4.1.18 Corrosion Under Insulation (CUI)
Corrosion under insulation (CUI) occurs when insulation or
fireproofing gets wet. Corrosion of underlying metal surfaces
becomes a serious problem with piping and vessels operating below
250F (121C). At this temperature, the metal does not get hot
enough to keep insulation dry during normal operation.
Refrigeration systems are particularly vulnerable to CUI.
The following techniques may be used to prevent CUI:
•
Properly wrap and caulk joints to keep insulation dry
•
Coat metal surfaces near flanged connections, valves, and pumps
prior to insulating since wetting of insulation due to leakage is
likely to occur in these locations
•
Use low-chloride insulation for austenitic stainless steel equipment and piping
•
Use closed cell, foamed glass insulation for austenitic stainless
steel equipment and piping.
Appendix S, NACE Standard RP0198 (current edition), “The
Control of Corrosion Under Thermal Insulation and Fireproofing
Materials—A Systems Approach,” (Houston, TX., NACE) presents
additional information on CUI.
1.4.1.19 Soil Corrosion
Soil corrosion (oxidation) is caused by differential concentration
cells involving oxygen, water, and various chemicals in the soil. It
is a major problem with underground piping and tank bottoms.
Incomplete mill scale on piping and tank bottoms, bacterial action,
pinholes in protective coatings, and coupling of dissimilar metals all
contribute to soil corrosion. Soil corrosion can also occur on the
bottom of piping, which is laid directly on the ground. If grass or
weeds are allowed to grow beneath and around piping, moisture will
remain for long periods of time, and the piping will corrode.
Soil corrosion can be reduced by excavating and backfilling with
clean, nonconductive sand. However, the best practice for
preventing soil corrosion is to locate piping well above grade and to
isolate tank bottoms from the soil by using underside membranes,
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asphalt, or concrete pours. Coatings and cathodic protection may
also be applied to piping and tank bottoms.
1.4.1.20 High-Temperature Sulfide Corrosion (Without Hydrogen Present)
High-temperature sulfide corrosion (without hydrogen present) is a
problem with hydrogen sulfide and other sulfur compounds above a
temperature of about 450F (232C), provided no liquid water is
present. The degree of corrosion depends on the concentration and
type of sulfur compounds involved. Sulfur compounds that cause
sulfur corrosion are:
•
Elemental sulfur
•
Polysulfides
•
Hydrogen sulfide (H2S)
•
Aliphatic sulfides
•
Aliphatic disulfides.
H2S is the most active of the sulfur compounds from a corrosion
standpoint. Most of the other compounds are considered inert in
terms of corrosion until the crude oil reaches the refinery and is
heated to elevated temperatures. There is some question as to
whether complex sulfur compounds or the H2S resulting from the
conversion of these compounds causes corrosive attack.
High-temperature sulfide corrosion problems began to show up in
the early 1940s in refineries when new processes called for higher
operating temperatures. It was quickly discovered that at
temperatures above 450F (232C), the addition of small amounts of
chromium to steel would reduce the corrosion associated with sulfur
on steel. The degree of improvement was related to the amount of
chromium added. A typical curve relating corrosion rates,
temperature, sulfur content, and chromium content is shown in
Figure 1.6.
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Figure 1.6 Modified McConomy Curves for H2S Corrosion
As Figure 1.6 illustrates, there is a rapid increase in corrosion rate
above 500F (260C), especially for carbon steel. Although flow
velocity and vaporization are not taken into account in Figure 1.6,
they also play a part in the corrosion rate of a given sulfur content.
In general, increases in vapor load and mass velocity increase the
severity of high-temperature sulfide corrosion.
The McConomy curves are a set of data useful for materials
selection and prediction of the relative corrosivity of crude oils and
their various fractions. Figure 1.6 is a modified McConomy curve
for liquid hydrocarbon streams having a total sulfur content of 0.5%.
It is modified from the original set of McConomy curves, which
tended to predict excessively high corrosion rates. The data in
Figure 1.6 demonstrate the significant benefit of alloying steel with
chromium. Essentially no sulfur corrosion occurs with ferritic or
martensitic stainless steels containing 12% chromium. The
austenitic steels also demonstrate excellent resistance.
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Figure 1.7 is a correction curve for sulfur content. The correction
factors can be used in conjunction with Figure 1.6 for predicting
corrosion rates at different sulfur levels.
Figure 1.7 Sulfur Correction Factor for McConomy Curves
The rate of sulfur corrosion starts to decrease as the temperature
exceeds 850F (454C). The most likely reason for the decrease is
coke formation. Relatively small changes in temperature can
significantly and unexpectedly affect sulfur corrosion rates. For
example, convection section tubes in crude oil feed furnaces and
fired heater reboilers normally operate at low enough temperatures
so that little corrosion occurs. However, accelerated, localized
attack may occur at points where convection tubes pass through tube
supports because of higher heat flux and temperature at these points.
Changing from plain to finned or studded heater tubes may also
pose corrosion problems. Increased sulfidation will be likely due to
the localized increase in tube metal temperature, which could be as
much as 200F (93C).
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1.4.1.21 High-Temperature Sulfide Corrosion (With
Hydrogen)
High-temperature sulfide corrosion with hydrogen present (H2S/H2
corrosion) is more severe than high-temperature sulfide corrosion
without hydrogen present. Hydrogen converts organic sulfur
compounds to hydrogen sulfide and corrosion becomes a function of
H2S concentration or partial pressure. H2S/H2 corrosion occurs
primarily in cat feed hydrotreating units, hydrodesulfurizers, and
hydrocrackers downstream of the hydrogen injection point.
Refinery experience has shown that corrosion data based on
traditional sulfur corrosion curves do not apply where hydrogen is
present in significant quantities.
The most reliable data for prediction of H2S/H2 corrosion rates are
based on the Couper-Gorman Curves developed from a NACE
International field survey of refiners. See Figure 1.8.
Figure 1.8 Modified Couper-Gorman Corrosion Curve—Carbon Steel in Naphtha
Desulfurizer
Figure 1.8 is a curve for carbon steel in naphtha desulfurizer,
hydrogen sulfide/hydrogen service. As shown by the iso-corrosion
curves, the mole percent H2S in the process stream and the
operating temperature define the expected corrosion rate. When the
corrosion rate is too high for carbon steel equipment to have a useful
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life, a more appropriate alloy can be selected. This can be
accomplished by multiplying the carbon steel rate by the factors
shown in Table 1.3 .
Table 1.3: Rate Factors for Alloy Selection
Metal/Alloy
Carbon and C-1/2 Mo steel
1 Cr-1/2 Mo
2-1/4 Cr-1 Mo
5 Cr-1/2 Mo
7 Cr-1/2 Mo
9 Cr-1 Mo
Rate Factor
1.0
0.957
0.906
0.804
0.736
0.675
There is little improvement in corrosion resistance of low-alloy
steels unless chromium content exceeds 5%. H2S/H2 corrosion is
more severe in gas oil desulfurization units than in naphtha units.
For gas oil desulfurizers and hydrocrackers, the corrosion rate for
carbon steel, shown in Figure 1.8 for a naphtha desulfurizer, should
be multiplied by 1.896.
Austenitic stainless steels, such as type 304L, type 321, or type 347
are used for most equipment operating above 500F (260C) in the
presence of H2S and hydrogen. Figure 1.9 is a corrosion rate curve
showing the dramatic improvement in corrosion resistance offered
by austenitic stainless steels over other alloys, including 12%
chromium stainless steel.
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Figure 1.9 Corrosion Rate Curves for H2S/H2 Environments
1.4.1.22 Naphthenic Acid Corrosion
Naphthenic acid corrosion is an aggressive form of corrosion
associated with crude oils from California (SJV), Trinidad,
Venezuela, Mexico (Maya), Eastern Europe, and Russia.
Naphthenic acid is a collective name for organic acids primarily
composed of saturated ring structures with a single carboxyl group.
These, along with other minor amounts of other organic acids, are
found in naphthenic-based crude oils.
Naphthenic acid content is generally expressed in terms of
neutralization or Total Acid Number (TAN), which is determined by
titration of the oil with potassium hydroxide (KOH) as described in
ASTM D664-95,1 “Standard Test Method for Acid Number of
Petroleum Products by Potentiometric Titration.” TAN is the
milligrams of KOH required to neutralize one gram of stock.
Naphthenic acids are generally considered corrosive only in the
temperature range of 350F to 700F (177C to 371C), with
corrosion peaking around 530F (276C). TANs in the range of 0.5
mg KOH/gm to 0.6 mg KOH/gm commonly cause naphthenic acid
corrosion. At a given temperature, the corrosion rate is roughly
proportional to the neutralization number, but the corrosion rate
triples with each 100F (37.8C) increase in temperature. The
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corrosion rate is also affected by velocity. Furnace tubes and transfer
lines have been severely affected when velocity exceeded 100 ft/s
(30 m/s).
In contrast to high-temperature sulfur corrosion, no protective scale
is formed. Low-alloy and stainless steels containing up to 12%
chromium provide little, if any, benefit over carbon steel. Sharpedged, streamlined grooves or ripples characterize metal surfaces
corroded by naphthenic acids.
Naphthenic acid corrosion occurs primarily in crude and vacuum
distillation units and less frequently in thermal and catalytic
cracking operations. It is most pronounced in locations of high
velocity, turbulence, and impingement, such as elbows, weld
reinforcements, pump impellers, thermowells, and steam injection
nozzles. Locations where freshly condensed acid fractions drip onto
or run down metal surfaces, such as tower downcomers, can be
seriously affected.
The following materials of construction may be used to mitigate
naphthenic acid corrosion:
•
Type 304 austenitic stainless steel under low-velocity conditions
provides good resistance but will pit.
•
Type 316 and type 317 molybdenum-containing austenitic stainless steels offer the highest resistance to naphthenic acids in
most circumstances.
•
Aluminum offers excellent resistance and can be used where
strength and erosion resistance are not priorities.
•
Alloy 20 stainless steel is highly resistant.
Blending crude oils having a high TAN with other crude oils is the
best method for controlling naphthenic acid corrosion. Blending
reduces the naphthenic acid content of the worst sidecut. As a result
of blending, the charge in the crude distillation unit should have a
TAN no higher than 1.0. If blending is not able to prevent attack,
type 316 or type 317 stainless steel can be used.
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1.4.1.23 High-Temperature Oxidation
As mentioned previously, oxidation is the chemical reaction that
takes place between a metal and oxygen to form an oxide.
Oxidation of many alloys creates an oxide film that, as it thickens,
forms an increasingly effective barrier between the metal and the
surrounding environment. The rate of oxidation is controlled by the
diffusion of metal outward or oxygen inward through the oxide
layer. Temperature, temperature fluctuations, the integrity of the
oxide layer, and the presence of other gases in the atmosphere
influence this diffusion.
High-temperature oxidation can result in excessive corrosion or
scaling and becomes a concern at approximately 1000F (538C). It
occurs when carbon steels, low-alloy steels, and stainless steels
react at elevated temperatures with oxygen in the surrounding air
and become scaled. The diffusion mechanism for protective scale
growth usually follows the parabolic rate law. Nickel alloys may
also become oxidized, especially if spalling of the scale occurs.
Scaling resistance is decreased by:
•
Thermal cycling
•
Applied stresses
•
Moisture
•
Sulfur-bearing gases.
In refineries, high-temperature oxidation is primarily limited to the
outside of furnace tubes, to furnace tube hangers, and other internal
furnace components exposed to combustion gases containing excess
air. Table 1.4 on page 45 lists the maximum metal temperatures for
various refinery metals, which result in acceptable scaling rates in
the presence of air. Acceptable scale rate refers to a weight gain of
less than 0.002 g/in.2/h.
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Table 1.4: Maximum Temperature for Long-Term Exposure to Air
Alloy
Carbon steel
Carbon-1/2 Mo
1-1/4 Cr-1/2 Mo
2-1/4 Cr-1 Mo
5 Cr-1/2 Mo
7 Cr-1/2 Mo
9 Cr-1 Mo
Type 410 stainless steel
Types 304, 321, and 347
stainless steel
Types 316 and 317 stainless
steel
Type 309 stainless steel
Type 310 stainless steel
Monel 400
Inconel 625
Incoloy 825
Hastelloy B-2
Hastelloy C-4 and C-276
Temperature
1050F (565C)
1050F (565C)
1100F (593C)
1175F (635C)
1200F (648C)
1250F (677C)
1300F (704C)
1500F (816C)
1600F (871C)
1600F (871C)
2000F (1093C)
2100F (1149C)
1000F (538C)
2000F (1093C)
2000F (1093C)
1400F (760C)
1800F (982C)
As the information in Table 1.4 demonstrates, alloying with both
chromium and nickel increases scaling resistance. Stainless steels
and nickel alloys provide oxidation resistance at temperatures above
1300F (704C). Silicon, even when present in small quantities, is
also effective in resisting high-temperature oxidation. Aluminum
applied by spraying, dipping, or cementation to the surface of steels
also improves oxidation resistance.
At elevated temperatures, steam decomposes at metal surfaces into
hydrogen and oxygen and may cause steam oxidation of steel.
Steam oxidation is more severe than air oxidation at the same
temperature.
The temperature limits provided in Table 1.4 should be lowered by
roughly 100F (37.8C) for high-temperature steam service.
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Fluctuating steam temperatures tend to increase the rate of oxidation
by causing scale to spall, exposing fresh metal to further attack.
A number of factors should be considered regarding hightemperature oxidation of alloys commonly used in refinery
processes, including:
•
1050F (565C) is the maximum temperature at which carbon
steel has adequate, long-term resistance to scaling.
•
Oxidation rates are not consistent with time; the oxidation rate
drops progressively as the scale layer builds up.
•
Temperature cycling increases the scaling rate of many hightemperature, heat-resistant alloys due to spalling of the scale.
•
Oxidation resistance of steels is approximately proportional to
the chromium content, but the resistance of a chromium-bearing
steel is enhanced by small amounts of silicon, aluminum, titanium, and columbium.
•
Traces of sulfur gases in high-temperature environments may
increase scaling of low and high-alloy steels, and high-nickel,
heat-resistant steels and nickel-base alloys should be used with
caution in hot gases containing appreciable amounts of sulfur.
1.5 Stress Corrosion Cracking (SCC)
SCC is the spontaneous cracking of alloys through the combined
action of corrosion and tensile stress. Failure is frequently caused
by simultaneous exposure to a seemingly mild chemical
environment and to a tensile stress well below the yield strength of
the material. Fine cracks penetrate deeply into the metal while the
surface exhibits only faint signs of corrosion and, often, a brittle
fracture may occur in what would normally be a ductile material.
The following types of stresses in a metal may be involved in SCC:
•
Residual stresses, such as bending or welding or from uneven
heating or cooling
•
Applied stresses, such as working stress from internal pressure
or structural loading.
In most instances, residual stresses are the major factor in SCC.
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Specific combinations of corrosives and alloys result in cracking.
Practically all alloys will crack under certain conditions. Table 1.5
presents a list of alloy systems and environments known to cause
SCC.
Table 1.5: Alloy Systems Subject to SCC
Alloy
Aluminum-base
Magnesium-base
Copper-base
Carbon steel
Martensitic & Precipitation
Hardening Stainless Steels
Austenitic Stainless Steels
Nickel-base
Titanium
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Environment
Air
Seawater
Salt & chemical combinations
Nitric acid
Caustic
HF solutions
Salts
Coastal atmospheres
Primarily ammonia &
ammonium hydroxide
Amines
Mercury
Caustic
Anhydrous ammonia
Nitrate solutions
Amine solutions
Carbonates
Seawater
Chlorides
H2S solutions
Chlorides (inorganic &
organic)
Caustic solutions
Sulfurous & polythionic acids
Caustic above 600F (315C)
Fused caustic
Hydrofluoric acid
Seawater
Salt atmospheres
Fused salt
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Typically, a certain alloy cracks in a certain medium and, if the
composition of the alloy or the medium is changed slightly, cracking
becomes more or less severe. Trivial changes in residual or alloying
elements may have a significant effect on cracking. For example,
pure copper is immune to SCC in ammonia, but if it is alloyed with
as little as 0.1% phosphorus, it becomes extremely susceptible.
The two most accepted theories for the mechanism of SCC are
anodic dissolution and stress-sorption cracking. However, neither
theory can account for all observed characteristics. Anodic
dissolution entails selective oxidation of local anodic areas. Grain
boundaries and other locations where deformation occurs are often
anodic to the surrounding metal. Local electrochemical action
encourages cracking to grow by corrosion of these anodic areas.
Tensile stresses break any protective film formed by the corrosion
process, promoting the corrosive action.
The stress-sorption cracking theory takes into account the surface
energy of the metal. This theory proposes that chemicals in the
solution are adsorbed on the metal surface, decreasing the surface
energy enough so that a tensile stress can cause the surface layer to
crack. The degree of adsorption is related to the electrical potential.
The critical cracking potential is the potential above which
adsorption occurs and below which desorption takes place. Not all
adsorbents significantly decrease the surface energy of a particular
metal.
No matter which SCC theory applies, there seems to be no
consistent pattern as to whether the fracture path through an alloy is
along grain boundaries (intergranular) or through grains
(transgranular). Sometimes, both modes of cracking occur
simultaneously, and the cracks can be heavily branched or
unbranched. The varying crack appearance for a given alloy in a
given environment can cause confusion when troubleshooting SCC
in refinery process streams.
•
The cracking process has three distinct stages:
•
Initiation—Can last a few minutes or several years.
•
Propagation—Proceeds at a relatively constant rate of cracking.
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1-49
Fast fracture—Occurs as cracking progresses and the effective
cross-section or wall thickness of the component is reduced,
leading to mechanical rupture.
The minimum stress for SCC can be as low as 10% of the alloy’s
yield strength. At stresses near the yield point, failure sometimes
occurs almost immediately upon exposure to the corrosive
environment.
Types of SCC include:
•
Chloride stress corrosion cracking (ClSCC)
•
Alkaline stress corrosion cracking (ASCC)
•
Carbonic acid
•
Polythionic acid stress corrosion cracking (PTA SCC)
•
Ammonia stress corrosion cracking (NH3 SCC)
•
Wet H2S cracking
•
Hydrogen blistering
•
Sulfide stress cracking (SSC), hydrogen induced cracking (HIC),
and stress oriented hydrogen induced cracking (SOHIC)
•
Hydrogen cyanide (HCN).
1.5.1 Chloride Stress Corrosion Cracking
(ClSCC)
ClSCC often occurs in austenitic stainless steels exposed to chloride
ions prevalent in many refinery aqueous environments. Only traces
of chloride may be required, along with a temperature above 130F
to 175F (54C to 79C) and either a low pH or the presence of
dissolved oxygen. Tensile stress must also be present and the higher
the stress, the less time to failure. Cracks are often transgranular,
but may be intergranular as well. If the right variables are present,
all of the 18 Cr-8 Ni stainless steels are susceptible to cracking in
chloride environments.
Austenitic stainless steels have been known to crack in steam
condensate and high-temperature water. Since very low chloride
levels can result in cracking, it is suspected that the cracking is
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actually caused by the chloride instead of the water. However, water
or moisture must be present for SCC and, as a result, cracking seems
to occur most frequently during shutdown conditions when
equipment is cooled and moisture condenses. Alternate wetting and
drying conditions promote ClSCC.
1.5.2 Alkaline Stress Corrosion Cracking
(ASCC)
Alkaline SCC occurs in carbon steels under tensile stress and
exposed to caustic, amine, and carbonate solutions at temperatures
above 150F (66C), 75F (23.9C), and 100F (37.8C),
respectively. With this type of SCC, cracks are intergranular and
oxide-filled, and the fracture surface appears to have been
embrittled.
Alkaline SCC also occurs in ferritic steels and austenitic stainless
steels. Residual tensile stress is a major factor in alkaline SCC and,
therefore, postweld heat treatment (stress relief) is used to provide
resistance to cracking. Cold-formed components are also stress
relieved for caustic service. Caustic concentrations of 50 ppm to 100
ppm are sufficient to cause cracking.
Like ClSCC, alternating wet and dry conditions accelerate caustic
SCC because they cause the caustic to concentrate. However, unlike
ClSCC the presence of oxygen is not required for cracking to occur.
Caustic (NaOH) is used in refineries to neutralize acids. At ambient
temperature, caustic can be handled in carbon steel equipment.
Carbon steel can also be used in environments with aqueous caustic
solutions up to 150F (66C). However, for caustic service above
150F (66C), carbon steel must be postweld heat treated to avoid
SCC at welds. Austenitic stainless steels, such as type 304, may be
used in caustic service up to 200F (93C), and nickel alloys or
Nickel 200 (N02200) are required at higher temperatures. When
sulfur compounds are present in caustic conditions at elevated
temperatures, Nickel 201 (N02201) should be used.
Dilute caustic (3% to 6% aqueous solution) is normally injected into
hot, desalted crude oil to neutralize any remaining hydrogen
chloride. When dilute caustic is appropriately dispersed in the hot
crude oil, puddles of caustic are prevented from collecting along the
bottom of the pipe where contact by caustic droplets can cause
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severe attack. When concentrated caustic is used, severe caustic
corrosion of the crude piping just downstream of the caustic
injection point can occur.
Refineries can experience unusual situations in which caustic
corrosion is encountered, including the following:
•
Traces of caustic can become concentrated in boiler feed water,
causing SCC in boiler tubes, which alternate between wet and
dry conditions due to overfiring.
•
Cracked welds or leaky tube rolls can form steam pockets that
concentrate caustic and lead to caustic embrittlement.
•
Caustic corrosion or gouging, found under deposits in heat
exchangers, results from concentrated caustic left behind after
boiler water permeates the deposits and evaporates.
Amine stress corrosion cracking is possible in non-stress relieved
carbon steel material. This type of cracking is a potential at
temperatures down to ambient. Some operators use a threshold
temperature, dependent on the type of amine in use. Stress relief
prevents this type of cracking.
Carbonate stress corrosion cracking has been reported in the light
ends handling equipment of fluid catalytic cracking units. The
carbonates come from the carbon dioxide produced in the unit.
Carbonates in sour water can cause cracking in the weld heat
affected zone of carbon steel material. Stress relief prevents this
type of cracking.
1.5.3 Carbonic Acid (Wet CO2)
In hydrogen plants, the hydrogen is produced by the water-gas
reaction of methane and steam at high temperature in conjunction
with a catalyst. The steam and methane reform into hydrogen,
carbon monoxide, and carbon dioxide (CO2). Carbon monoxide
then reacts with additional water to form CO2 and hydrogen. The
effluent gas is then contacted with an alkaline solution, such as
potassium carbonate, to remove the CO2.
CO2 corrosion of steel can occur whenever the system operates
below the dew point of water. This type of corrosion can be severe.
Where condensation occurs, corrosion rates can exceed 1 in./y (2.5
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cm/y). Corrosion-resistant alloys, such as Monel (70% Ni, 30%
Cu), aluminum, stainless steels, and copper-nickel, may be used to
mitigate corrosion caused by CO2. The addition of at least 12%
chromium as an alloying element protects steel from attack by CO2.
In vapor recovery sections of catalytic cracking units, CO2 may
react with ammonia, forming ammonium carbonates. When the pH
is above 9.5, the ammonium carbonate may cause SCC of steel
piping and equipment.
1.5.4 Polythionic Acid Stress Corrosion
Cracking (PTA SCC)
PTA SCC occurs in austenitic stainless steels in the sensitized
condition when exposed to polythionic acids under conditions of
residual or applied tensile stress. As mentioned previously,
sensitization is the harmful precipitation of chromium carbides in an
almost continuous network around the metal grains of austenitic
stainless steel. The formation of the chromium carbides leaves a
chromium-depleted zone at the grain boundaries, rendering the alloy
susceptible to intergranular corrosion. Sensitization occurs from
750F to 1550F (399C to 843C), is time-temperature dependent,
and is most rapid at about 1250F to 1350F (677C to 732C).
Polythionic acids form from the interaction of metal surface
sulfides, moisture, and oxygen, all of which can be present when
refinery equipment containing sulfide films is opened during
shutdowns and turnarounds. Sulfur acids responsible for the
formation of PTA readily form in desulfurizers, FCU regenerators,
and hydroprocessing units. These acids are aggressive cracking
agents. For example, cracking has occurred through 3/8-in. (9.5
mm) wall austenitic stainless steel heater tubes in less than one hour
at ambient temperature.
PTA SCC can be prevented by:
•
Selecting low carbon and stabilized grades of austenitic stainless
steel to avoid in-service or welding sensitization
•
Applying an initial thermal stabilization treatment to chemically
stabilized grades of stainless steel that will be exposed to longterm, high-temperature service
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1-53
Following proper shutdown procedures to exclude oxygen and
moisture.
Appendix P, NACE RP0170 (current edition), “Protection of
Austenitic Stainless Steels and Other Austenitic Alloys from
Polythionic Acid Stress Corrosion Cracking During Shutdown of
Refinery Equipment,” (Houston, TX., NACE) presents prevention
measures for PTA SCC.
1.5.5 Ammonia Stress Corrosion Cracking
(NH3 SCC)
All copper alloys used in refineries can fail by SCC in a moist
ammonia atmosphere. This type of damage is typically seen in
copper alloy heat exchanger tubing and can be particularly
aggressive when oxygen is introduced during equipment openings.
Ammonia-bearing, fractionation tower overhead systems often have
admiralty brass condenser bundles installed for cooling water and
process side corrosion resistance. If the tubes contain residual stress
from tubing fabrication or tube expansion, ammonia SCC can occur.
Copper alloys are used in a variety of refinery water applications.
Some of these contain organic matter which decays and produces
ammonia in systems where it would not normally be expected. The
brasses or bronzes seem to be the copper alloys most susceptible to
ammonia SCC. The copper-nickel alloys are less likely to
experience cracking.
Ammonia is not widely used in boilers to neutralize CO2 because it
is corrosive to copper alloys commonly found in steam and
condensate utilization equipment. However, in an all-steel system,
ammonia would be a suitable neutralizer.
1.5.6 Wet H2S Cracking
Wet H2S cracking is one form of hydrogen damage in wet H2S
environments. Other forms of damage caused by the presence of
hydrogen in wet H2S environments include:
•
Hydrogen blistering
•
Sulfide stress cracking (SSC)
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•
Hydrogen induced cracking (HIC)
•
Stress oriented hydrogen induced cracking (SOHIC)
•
Hydrogen cyanide (HCN).
H2S is a relatively mild acting corrosive to carbon steel, and general
corrosion rates tend to be low. However, during the corrosion
process, considerable amounts of hydrogen can be liberated, which
can have significant, detrimental effects on welded pressurecontaining components. Generally, hydrogen blistering and cracking
are common to refinery equipment that contains greater than 50 ppm
H2S in water, between ambient temperatures and 300F (149C).
Longitudinally or spiral welded pipe is also susceptible in these
conditions. Seamless pipe, forgings, and castings do not usually
crack or blister in wet H2S service as long as hardness controls are
maintained on weldments.
Hydrogen damage in wet H2S service is caused by the generation of
atomic hydrogen as a by-product of the corrosion reaction and the
subsequent diffusion of the atomic hydrogen into the steel. Atomic
hydrogen (H) and molecular hydrogen (H2) are produced in the
corrosion reaction of steel with aqueous H2S as follows:
Fe + H2S  FeS + 2 H followed by 2H  H2
Under ordinary acidic conditions, molecular H2 forms at the surface
of the steel and, if produced slowly at low corrosion rates, it
harmlessly dissipates. However, when sulfide scale is present, the
sulfide acts as a negative catalyst and discourages the reaction 2H
 H2. As a result, the atomic hydrogen penetrates the steel,
accumulating in the crystal structure and affecting the steel’s
mechanical properties. Other compounds, such as sulfide, cyanide
(HCN), phosphorus, antimony, selenium, and arsenate ions, which
are called recombination poisons or catalyst poisons also interfere
with the conversion of atomic hydrogen to molecular hydrogen. In
the presence of a catalyst poison, the surface concentration of
atomic hydrogen rises, and a corresponding increase occurs in the
amount of hydrogen diffusing into the metal. Atomic hydrogen can
diffuse through solid steel at rates of several cubic centimeters per
square centimeter per day.
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Upon diffusion into the steel, atomic hydrogen can affect the metal
in several ways, such as:
•
At laminations or inclusions, the hydrogen atoms may recombine to form molecular hydrogen, which is then too large to diffuse further through the steel, becoming trapped. If laminations
are large enough, the internal hydrogen pressure may become
sufficient to cause distortion and formation of a bulge on the surface (blistering).
•
High concentrations of atomic hydrogen can result directly in
embrittlement and cracking of the steel, particularly highstrength or high-hardness steels. Embrittlement and cracking
often occur in heat-affected zones in low-strength steels that
have not been postweld heat treated.
Wet H2S cracking of steel occurs during the advanced stage of
hydrogen saturation. The structure becomes brittle as a result of the
strains imposed on the metal lattice by the presence of microbubbles
of hydrogen gas. In these situations, the structure will fracture
instead of deforming when subjected to stress. Microcracks exist in
most structures as a result of fabrication, heat treatment, or welding.
In the absence of atomic hydrogen, these microcracks are unlikely
to become more severe. However, in the presence of atomic
hydrogen, brittle failure at low stress levels can result.
Embrittlement of the charged steel can be removed by lowtemperature heat treatment once the component is removed from the
hydrogen-generating source. Molecular hydrogen trapped in steel
cannot be removed. Hydrogen embrittlement may be prevented by:
•
Using coatings to protect steel from H2S
•
Using inhibitors to minimize H2S corrosion
•
Lowering the stress level
•
Using a lower-strength steel that is compatible with design specifications
•
Avoiding metal deformation, bending, cold working, and peening
•
Using alloys resistant to embrittlement, such as Monel (70% Ni,
30% Cu), Inconel, and 300-series stainless steels.
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1.5.7 Hydrogen Blistering
Hydrogen blistering is caused by atomic hydrogen diffusing into
steel and becoming trapped at voids, laminations, or non-metallic
inclusions. As mentioned previously, the hydrogen atoms entering
these sites combine to form molecular hydrogen, which cannot
escape by outward diffusion. The expansion pressure of the
accumulating hydrogen gas produces a separation in the
component’s through-wall and becomes apparent as a blister on the
metal surface.
Blisters may appear on either or both surfaces of a plate or on top of
one another, depending on the location of the lamination. They vary
in size and appearance from small protrusions to swellings several
feet or more in diameter. Increasing blister growth can produce
tears in the surface and result in loss of the pressure-retaining
capability of the equipment.
Hydrogen blistering is controlled or eliminated by reducing or
eliminating the hydrogen activity. This can be accomplished by:
•
Using alloy or alloy-clad materials resistant to hydrogen-producing corrosion
•
Inhibiting the corrosion process
•
Using steels processed to minimize inclusions.
1.5.8 Sulfide Stress Cracking (SSC)
SSC is a form of hydrogen embrittlement cracking that occurs in
high-strength steels, hard welds, and hard weld heat-affected zones
(HAZs) that are subjected to sour environments with tensile stress at
temperatures below 180F (82C). A steel’s susceptibility to SSC is
highly dependent on its composition, microstructure, strength,
residual stress, and applied stress levels. For example, carbon steels
with a hardness level above Rockwell C 22 or BHN 241 are
considered susceptible to SSC, but steel composition and
microstructure influence the threshold hardness for susceptibility.
In refineries, SSC is seen in:
•
High-strength 12 Cr (type 410 stainless steel) valve trim
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•
Compressor shafts, sleeves, or other high-strength machinery
parts exposed to sour gas
•
Bolts
•
Alloy steel relief valve springs that are not A1 plated or isolated
from sour relief gas by bellows design
•
Hard welds and weld heat-affected zones.
Postweld heat treatment, which reduces residual stresses and
tempers the microstructure, along with controlling welding
parameters are the best approaches to mitigating SSC. For cracking
of standard 12% chromium steel valve trim, changing to austenitic
stainless steel or doubling heat treatment of the 12 Cr trim can
increase resistance to SSC. A modified temper of high-strength
bolts can reduce hardness and the subsequent tendency to crack.
1.5.9 Hydrogen Induced Cracking (HIC)
HIC results from parallel hydrogen laminations that link up to
produce a through-wall crack with no apparent interaction with
applied or residual stress. HIC is driven by stresses from the internal
buildup of hydrogen at blisters. It is a function of steel cleanliness
and relates back to the method of steel manufacture, impurities
present, and their form.
Non-homogenous, elongated sulfide or oxide inclusions occurring
parallel to the plate rolling direction are typically associated with
HIC. These inclusions serve as sites for formation of microscopic
hydrogen blisters that grow and eventually connect via stepwise
cracks. In fact, HIC is sometimes called stepwise cracking.
Since HIC is not stress-dependent or associated with hardened
microstructures, postweld heat treatment is of little value.
Restricting trace elements, such as sulfur, and controlling
manufacturing variables for steel provide HIC-resistance.
1.5.10 Stress Oriented Hydrogen Induced
Cracking (SOHIC)
SOHIC is similar to HIC except that cracking is stress-driven and
has a crack direction perpendicular to the primary stress direction.
SOHIC is commonly found in the heat-affected zone of welds where
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it initiates from other cracks or defects. Since stress is involved in
crack development and propagation, postweld heat treatment is
somewhat effective in reducing SOHIC. Controlling manufacturing
variables and trace elements is also effective.
1.5.11 Hydrogen Cyanide (HCN)
HCN is a significant factor in hydrogen blistering and cracking of
pressure-containing equipment, especially in the vapor recovery
sections of fluid catalytic cracking and delayed coking units. HCN,
like ammonia, is formed from nitrogen-bearing feedstocks.
Equipment affected by HCN includes:
•
Fractionator overhead drums
•
Compressor interstage and high-pressure stage separator drums
•
Absorber and stripper towers
•
Light ends debutanizer and depropanizer towers.
HCN destroys the protective iron sulfide film normally present on
carbon steel and converts it into soluble ferrocyanide complexes,
exposing the steel. As a result, the steel corrodes rapidly, allowing
atomic hydrogen to penetrate and blister and/or crack the metal.
Reducing HCN concentration through water washing can minimize
its effect on corrosion or blistering. In addition, converting HCN to
harmless thiocyanates by injecting dilute solutions of sodium or
ammonium polysulfide is also effective in mitigating HCN-induced
corrosion. Filming amine corrosion inhibitors have also been used.
1.5.12 SCC Prevention
SCC in refineries can be prevented in several ways:
•
Austenitic stainless steels are not normally used in cooling water
service or in overhead condenser service where water and chlorides are present.
•
In fresh water systems, stainless steel has been used successfully
by ensuring flow characteristics that prevent stagnant or lowflow regions through the exchanger tube side.
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•
Only low-carbon and chemically stabilized austenitic stainless
steel grades should be used in high-temperature desulfurization,
hydroprocessing, and catalytic cracking units.
•
Proper shutdown procedures, such as those found in NACE
RP0170, “Protection of Austenitic Stainless Steels and Other
Austenitic Alloys from Polythionic Acid Stress Corrosion
Cracking during Shutdown of Refinery Equipment,” should be
followed when austenitic stainless steel equipment is opened to
the atmosphere for cleaning or inspection.
•
Carbon steel welds and cold-formed equipment in caustic service above 150F (66C) and in amine service regardless of temperature should be postweld heat treated.
•
Overfiring of boilers should be avoided to prevent caustic
buildup in boiler tubes, and leaks in hot boiler water systems
should be promptly repaired.
1.5.13 Inspecting for Wet H2S Damage
Wet H2S cracking of any degree cannot be ignored. However, the
first priority must be given to cracking with the greatest potential to
threaten the pressure integrity of equipment. Generally, experience
has shown that this is most likely to occur when:
•
The equipment has a history of blistering.
•
Significant repairs or alterations have been made that have not
been postweld heat treated, particularly if they were in response
to wet H2S damage. The term significant in this situation generally means welds greater than 50% of the wall thickness, or ½ in.
in depth, or greater than a few inches in length. Butt patches and
nozzle, shell courses, or head replacements are of major concern.
Within a piece of equipment that may be experiencing wet H2S
damage, the highest priority should be given to inspection of the
pressure-containing welds at seams and nozzles. Deep cracks,
greater than 3/8 in. deep or 50% of the wall thickness, typically
occur at nozzles and seams.
Since wet H2S damage can have catastrophic consequences, many
refineries use a system to prioritize and execute inspections for this
type of damage. Normally, a distinction is made between the first
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inspection of an equipment item for wet H2S cracking and
reinspections of the same equipment. First inspections should take
into consideration the following key factors:
•
Severity of service conditions
•
Susceptibility of the steel to cracking
•
Potential consequences of a leak.
The frequency and priority of follow-up inspections are primarily
driven by the results of the first inspection.
To establish the inspection schedule and priority of first-time
inspections for wet H2S damage on new and old equipment, the
following steps, with examples, may be followed:
1. Assign a service severity factor.
For equipment in wet H2S service, use a severity number of
2.
Add 1 if the H2S content in water is greater than 2000 ppm.
Add 2 if cyanides are present.
Add 2 if the equipment is in hydrocarbon vapor or LPG
service.
In assigning severity numbers, keep in mind that upset
conditions can result in significant damage that would be
unexpected under normal operating conditions.
2. Assign a steel susceptibility factor based on fabrication and
repair history.
History
Cracking Requiring Weld Repair, no
PWHT
Blistering/Linking (HIC or Stepwise
Cracking)
Cracking Requiring Weld Repair, PWHT
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16
14
12
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Blistering
Cracking, No Weld Repair Required
Non-Original
Welds
or
Welded
Alterations
Conventional Steel, No PWHT
Conventional Steel, PWHT
12
12
10
9
6
3. Establish a cracking factor by multiplying the service severity
factor times the steel susceptibility factor.
4. Evaluate the relative consequences of a leak by assigning a
fluid service category for each piece of equipment.
Category 1 (highest consequence)—For LPG, rich-amine,
vapor streams containing 3 wt% H2S and all streams above
1500 psig operating pressure.
Category 2 (moderate consequence)—For hydrogen, fuel
gas, natural gas, lean-amine, liquid streams that vaporize
quickly upon release, and all streams above 500 psig operating pressure.
Category 3 (lowest consequence)—For other sour hydrocarbon and sour water streams.
5. Determine the required inspection schedule.
Equipment to be inspected during the next shutdown
Fluid Category 1 with Cracking Factor 35
Fluid Category 2 with Cracking Factor 55
Equipment to be inspected within 10 years
Fluid Category 1 with Cracking Factor of 0 to 34
Fluid Category 2 with Cracking Factor of 10 to 54
Fluid Category 3 with Cracking Factor 20
Equipment not requiring special inspection
Fluid Category 2 with Cracking Factor of 0 to 9
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Fluid Category 3 with Cracking Factor 0 to 20
1.5.14 High-Temperature Hydrogen Attack
(HTHA)
HTHA is primarily a problem in downstream operations in which
carbon and low-alloy steels are exposed to hydrogen at temperatures
above 430F (221C) and partial pressures above 200 psi.
Hydroprocessors, hydrotreaters, naphtha hydrotreaters, catalytic
reformers, and hydrogen manufacturing plants are exposed to
conditions promoting HTHA. When damaged, the steel loses tensile
strength and ductility and, if under stress, can crack.
At high temperatures, molecular hydrogen dissociates into hydrogen
atoms, which permeate the steel causing deterioration in the steel’s
mechanical properties. The dissociation of molecular hydrogen into
hydrogen atoms is an equilibrium reaction, dependent only on
temperature. At a given temperature, a fixed percentage of the
hydrogen will exist in the atomic state. In hot hydrogen
environments, atomic hydrogen always exists and will diffuse into
and through the walls of steel equipment.
Within the steel, the hydrogen reacts with other elements, such as
carbon, to form gases, primarily methane. The reaction follows:
Fe3C + 2H2  3Fe + CH4
The methane cannot diffuse out of the steel and accumulates
principally at the grain boundaries. Dislocations, internal voids,
inclusions, and other gross discontinuities can be other methane
formation points. High local, internal stresses eventually develop
and become so great that the metal will fissure. Cracks in hydrogendamaged steel are initially microscopic in size. However, in
advanced stages, they substantially deteriorate the steel’s
mechanical properties.
Since carbon acts as the major strengthening agent in steel, the
removal of carbon (decarburization) by the reaction with atomic
hydrogen causes a loss of strength.
In addition to bubbles and fissures that occur within the steel and
cannot be seen on the surface, surface blisters may also be formed.
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These blisters, which contain methane, can be seen on the steel
surface. They form when high temperatures cause carbon in the
steel to diffuse to the metal surface and combine with atomic
hydrogen to form methane.
Whether steel deteriorates by surface decarburization or by methane
fissuring and internal decarburization primarily depends on
hydrogen temperature and pressure and alloy content of the steel.
At relatively high temperatures and low pressures, surface
decarburization occurs more rapidly than internal attack. However,
at relatively high pressures and low temperatures, internal attack
may proceed without significant surface decarburization. When
pressure and temperature are sufficiently high, both mechanisms can
occur simultaneously.
The pressure-temperature conditions under which carbon steel and
other alloyed steels are subject to HTHA are shown in Figure 1.10.
Figure 1.10 Operating Limits for Steels in Hydrogen Service
This figure is a simplified Nelson Curve that can be found in
Appendix O, API Publication 941, “Steels for Hydrogen Service at
Elevated Temperatures and Pressures in Petroleum Refineries and
Petrochemical Plants” (Washington, D.C.: American Petroleum
Institute, 1997). The curves shown reflect a large amount of
empirical data based on long-term experience with actual operating
equipment in many refineries. API periodically revises the curves
as new experiences are reported. For example, experience has
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shown carbon-1/2 Mo steel to be unreliable for hydrogen service.
As a result, the carbon-1/2 Mo curve has been deleted from the
most recent issue of API Publication 941 for new fabrication.
The curves in Figure 1.10 serve as a guide in the selection of steels
for hydrogen service. Steels containing strong carbide stabilizing
agents, such as molybdenum, chromium, tungsten, vanadium, and
columbium, limit the amount of carbon available for the formation
of methane.
Since the curves are based on plant experience and not
thermodynamics or kinetics principles, many refiners add a design
margin, such as 50F (10C) to the temperature parameter for actual
equipment designs.
HTHA is usually not uniform throughout an affected component.
Attack is initiated first in areas of high stress where hydrogen
preferentially diffuses. Weld heat-affected zones are more
susceptible than base metal and weld metal. High carbon content
decreases resistance to HTHA.
1.6 Metallurgical Failures
The metallurgical properties, such as strength, ductility/strain
capability, toughness, and corrosion resistance can change in service
due to microstructural changes as a result of thermal aging at
elevated temperatures. In addition, at elevated temperatures, certain
elements and compounds produce compositional changes in metals,
which can greatly affect their properties. In refineries, primarily
carbon, carbon monoxide, carbon dioxide, steam, and hydrogen
cause chemical changes.
These changes usually result in
degradation of mechanical properties accompanied by severe
cracking and embrittlement.
Changes in metal properties are difficult to detect.
Steel
composition and microstructure, operating temperature, and
accumulated strain/stress are the most important factors that
determine susceptibility to metallurgical changes. Often an
equilibrium state of change is reached and further changes will not
occur. Once the metallurgical properties are changed in service,
they are usually not recovered. Heat treatment can be effective but
is often only temporary. To prevent further degradation, operating
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conditions can be adjusted to lower severity. Startup and shutdown
procedures can also be altered to prevent failure or further damage
from occurring despite the degraded physical properties.
In addition to low creep rates and high stress rupture strengths,
metals and alloys used in high-temperature refinery service must
have good structural stability. The most serious structural changes
that may occur as a result of exposure to high temperatures include
the following:
•
Grain growth
•
Graphitization
•
Hardening
•
Sensitization
•
Sigma phase formation
•
885F (475C) embrittlement
•
Temper embrittlement
•
Liquid metal embrittlement.
1.6.1 Grain Growth
Grain growth occurs when steels are heated above a certain
temperature, beginning at about 1100F (593C) for carbon steel. It
is most pronounced at 1350F (732C). The amount of growth
depends on the maximum temperature reached and the length of
time at temperature. Austenitic stainless steels and high nickelchromium alloys do not become subject to grain growth until heated
to above 1650F (899C).
Grain growth lowers the tensile strength, but increases both creep
and rupture strength. In practice, grain growth has not been a
significant factor in refinery failures. However, it is very useful for
pinpointing furnace operational problems that have led to localized
overheating failures of furnace tubes. Metallographic examination
of the microstructure of failed components can reveal, through grain
growth, the temperature to which the component was exposed.
Refinery fire damage evaluations apply this technique.
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1.6.2 Graphitization
Graphitization occurs when the normal pearlite (ferrite/cementite)
grains in steels decompose into soft, weak ferrite grains and graphite
nodules. Long-term exposure in the 825F to 1400F (440C to
760C) temperature range can result in graphitization. It is found
mostly with carbon steels and carbon-1/2 Mo steels. Chromium is
added to eliminate this problem.
There are two general types of graphitization. The first is random
graphitization in which graphite nodules are distributed uniformly
throughout the steel. While this type lowers the room temperature
tensile strength, it has little effect on creep resistance. The second
type of graphitization, called chain graphitization, results in highly
concentrated flakes or graphite in local regions. Mechanical failure
is likely to originate in areas of high graphite concentration. The
stress rupture strength is also drastically reduced.
1.6.3 Hardening
Hardening of steels is the result of martensitic formation after
heating carbon steel to above the upper critical temperature
followed by rapid cooling. A brittle martensitic carbide structure is
formed which is undesirable for refinery piping, furnace tubes, or
pressure vessels. Hardening can occur in the course of welding
fabrication or when steels are exposed to severe overheating, such
as in a fire. Hot bending can also be a source of hardening.
Welding of carbon steels having less than 0.25% carbon generally
presents no hardening problems because the usual cooling rates are
not fast enough to permit martensitic formation. However, carbon
steel with more than 0.35% carbon, low-alloy steels, and the
martensitic straight chromium stainless steels will harden simply by
air cooling after welding. Similarly, during fire exposure, these
hardenable materials can become extremely hard and brittle to the
extent they are not serviceable.
To prevent cracking of hardened metal after welding, preheat
treatment and postweld heat treatments are used. These will be
discussed in Chapter 15, Materials of Construction for Refinery
Applications. In the case of fire-damaged material, hardness
surveys using portable testers can be used to identify equipment and
piping hardened by overheating and quenching.
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Conversely, softening can also be a problem with refinery
equipment. Some pressure vessels are made of low-alloy steels that
are quenched and tempered or normalized and tempered to optimize
design strength. Subsequent welding, heating for bending, or
exposure to fire can lower steel strength so that replacement or
reheat treatment will be required. Commonly used bolting ASTM
A1932 grade B 7 is an example of an intentionally hardened
component that may experience softening. Hydroprocessing
reactors made of 2-1/4 Cr-1 Mo are other examples.
1.6.4 Sensitization
Sensitization was previously addressed in this chapter during the
examination of intergranular cracking and polythionic acid SCC.
Sensitization occurs when austenitic stainless steels are heated in the
range of 700F to 1500F (371C to 816C). For optimum corrosion
resistance, these steels normally are supplied in the solution heattreated condition, with carbides fully dissolved in the austenitic
matrix. During elevated temperature exposure, either in service or
at the time of welding, chromium carbides precipitate at grain
boundaries. As a result, the grain boundaries are depleted of
chromium and become more susceptible to corrosion. Sensitizing
does not appreciably affect the mechanical and heat-resisting
properties of stainless steels.
Sensitization can be avoided by using low carbon and stabilized
grades of austenitic stainless steels when welding and in hightemperature service. Sensitizing can be reversed by solution heat
treatment after welding, but this is usually impractical because the
component needs to be heated to above 2000F (1093C) and water
quenched.
1.6.5 Sigma Phase
Sigma phase formation occurs when austenitic and other stainless
steels with more than 17% chromium are held at temperatures
between 1000F to 1500F (538C to 816C) for an extended period
of time (50 hours to 200 hours). Sigma is a hard, brittle, nonmagnetic phase containing approximately 50% chromium. Cold
work promotes its formation. With embrittlement, there is an
increase in the alloy’s room temperature tensile strength and
hardness accompanied by a decrease in ductility to the point of
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brittleness. As a result, cracking is likely to occur during cooling
from operating temperatures, during handling, and during repair
welding.
High-nickel alloys are immune to sigma formation, but highchromium alloys are susceptible. The susceptibility to and rate of
sigma phase formation in intermediate alloys depend on the ratio of
nickel to chromium. During sigma transformation, neighboring
areas are depleted of chromium, which can lead to failures along
grain boundaries if the material is exposed to corrosive conditions.
Sigma is most likely to be found in cast furnace tubes and other cast
furnace components. Cast stainless steel containing 25% chromium
and 20% nickel is especially susceptible to sigma phase formation.
The sigma phase can be dissolved into the austenite matrix by
heating the embrittled component to between 1800F and 2000F
(982C to 1093C). As a result, ambient temperature ductility is
restored. To avoid sigma phase embrittlement, an austenitic
stainless steel and its weld deposits should be limited to a ferrite
content no higher than 10%.
1.6.6 885F (475C) Embrittlement
885F (475C) embrittlement occurs after aging of ferritecontaining stainless steels at 650F to 1000F (343C to 538C) and
produces a loss of ambient temperature ductility. Refinery failures
result from cracking of both wrought and cast steels during
shutdowns. To avoid 885F (475C) embrittlement, high-chromium
stainless steels, such as type 430 and type 446, duplex stainless
steels, and austenitic stainless steels containing high amounts of
ferrite are restricted to service temperatures below 650F (343C).
Restricting the ferrite content of austenitic stainless steels to 10% or
less can mitigate 885F (475C) embrittlement. Heating the
embrittled component to 1200F (648C), followed by rapid cooling
can restore ductility.
1.6.7 Temper Embrittlement
Temper embrittlement occurs in low-alloy steels that are held for
long periods of time at temperatures between 700F to 1050F
(371C to 565C). This type of embrittlement results in a loss of
toughness that is not evident at operating temperatures but appears
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at ambient temperature and can result in brittle fracture. The
potential for brittle fracture of low-alloy equipment increases with
service time in the embrittlement range. Some refinery units may
have been in service long enough that they contain components
capable of brittle fracture during startup or shutdown. The 2-1/4 Cr1 Mo alloy commonly used in hydrotreating and hydrocracking
units may be particularly vulnerable to brittle fracture because it is
used at elevated temperatures.
In extreme cases, transition temperature shifts as high as 200F
(93C) have been experienced. For instance, even though the steel
is fully ductile at operating temperatures, it can quickly pass into the
brittle range as the temperature is lowered during unit shutdown.
Any existing crack or defect would then increase in severity with or
without an impact load.
Limiting pressurization to 25% of the design value until the
equipment temperature is above the transition temperature mitigates
temper embrittlement of older equipment. Temper embrittlement is
also reversible, and the steel can be de-embrittled by heating to
above 1100F to 1200F (593C to 648C), followed by cooling to
room temperature. Embrittlement can be expected to return if the
equipment is exposed to the embrittlement range again. Restricting
the amount of residual elements, such as tin, phosphorus, arsenic,
manganese, and silicon, reduces the susceptibility of new equipment
to temper embrittlement.
1.6.8 Liquid Metal Embrittlement (LME)
LME is a form of catastrophic brittle failure of a normally ductile
metal caused when it is in, or has been in, contact with a liquid metal
and is stressed in tension. In refineries, LME has been experienced
in copper alloys exposed to mercury and austenitic stainless steels
contaminated by molten zinc or aluminum.
Mercury is found in some crude oils. Refinery distillation processes
can condense and concentrate the mercury at low spots in
equipment, such as condenser shells. Liquid mercury has also been
introduced into refinery streams by failure of process instruments
that utilize mercury. Copper alloys, such as those used for condenser
tubes, when contacted by mercury, are wetted intergranularly and, as
a result, fracture under relatively low tensile loads. Examination of
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the fracture surface reveals shiny mercury metal adhering to the
surface.
Welding and fire exposure can produce LME from molten zinc that
is generated from galvanized components as well as from aluminum
insulation coverings in intimate contact with austenitic stainless
steels. Wetting of austenitic steel grain boundaries by zinc or
aluminum causes strength reduction in the metal, which is
conducive to intergranular cracking.
1.6.9 Carburization
Carburization is caused by carbon diffusion into the steel at elevated
temperatures. Coke deposits on furnace tubes are a source of carbon
for carburization. Carburization depends on the rate of diffusion of
elemental carbon into the metal and increases rapidly with
increasing temperature. An increasing carbon content causes an
increase in the hardening tendency of ferritic steels. When
carburized steel is cooled, a brittle structure results, which may spall
or crack.
All steels are susceptible to carburization under the proper
conditions. However, susceptibility decreases with increasing
chromium content in steels. The austenitic stainless steels seem to
offer more resistance to carburization than the straight chromium
steels due to their higher chromium content as well as their nickel
content.
1.6.10 Metal Dusting
Metal dusting is catastrophic, highly localized carburization of
steels exposed to mixtures of hydrogen, methane, carbon monoxide,
carbon dioxide, and other light hydrocarbons in the temperature
range of 900F to 1500F (482C to 816C). With metal dusting,
attack is in the form of small pits filled with carbon or general,
uniform waste that yields a crumbly residue composed of graphite,
metal, carbides, and oxides. Trace amounts of sulfur seem to inhibit
metal dusting. Metal dusting failures can occur in dehydrogenation
units, fired heaters, coker heaters, cracking units, and gas turbines.
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Metal dusting reactions result from a complex series of steps in
which a reducing gas, rather than an oxidizing agent, is usually the
reactant. Copper, for example, has poor oxidation resistance, but is
not affected by metal dusting, while ordinary stainless steels are
known for their oxidation resistance, but are susceptible to metal
dusting. In general, the rate of attack of metal dusting increases
linearly with temperature.
1.6.11 Decarburization
Decarburization, mentioned previously during the discussion of
high-temperature hydrogen attack (HTHA), is the loss of carbon
from the surface of a ferrous alloy as a result of heating in a medium
that reacts with carbon. Decarburization can be found only by
microscopic examination.
When carbon is removed from the surface of a steel, the surface
layer is converted to almost pure iron, which results in considerably
lower tensile strength, hardness, and fatigue strength. The presence
of a decarburized layer is usually not serious unless creep and
fatigue are problems. However, the occurrence of carburization in
operating equipment is evidence that the steel has been overheated
and suggests other effects may be present.
1.6.12 Selective Leaching
Selective leaching is the preferential loss of one alloy phase in a
multiphase alloy. In the brasses, such as admiralty brass used in
refinery cooling water systems, selective leaching is called
dezincification. In copper-nickel alloys, it is called denickelfication,
and in cast iron, the selective loss of iron is termed (incorrectly)
graphitization.
There are two common types of dezincification exhibited in brass:
•
Uniform, layer type
•
Localized, plug-type.
In both types, the brass first dissolves by corrosion and copper,
being more noble than zinc, subsequently plates out. As a result, the
dezincified areas contain as much as 95% copper and have become
brittle and possess essentially no strength. With plug-type
dezincification, exchanger tubes are suddenly discovered perforated
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when dezincified small areas, plugs, are blown out by water
pressure or during bundle hydroblast cleaning.
Selective leaching is favored by stagnant flow conditions that allow
deposits to settle out on tubing surfaces, which produces leaching as
a result of crevice corrosion mechanisms. The presence of oxygen
is not required for selective leaching, but deaeration reduces the
likelihood of attack in most waters. In brass, the addition of small
amounts of phosphorus, arsenic, or antimony as an inhibitor greatly
reduces the risk of dezincification, except in highly aggressive
waters.
1.7 Mechanical Failures
In the absence of corrosion, equipment will eventually deteriorate.
This deterioration normally occurs very slowly, unless incorrect or
defective materials were initially installed or process conditions
exist that exceed a material’s mechanical properties. Major pieces
of equipment are inspected and tested before being placed into
operation. However, mixing of materials can often occur with
smaller items, such as valves and fittings.
Mechanical damage, overloading of structural members, and overtightening of bolts represent a large portion of mechanical failures.
Accidental over-pressuring or brittle fracture of equipment
occasionally occurs in fixed equipment. In contrast, fatigue failures
are fairly common with machinery having highly stressed,
reciprocating parts.
Operational changes in process temperature or pressure, upsets,
overfiring of furnaces to increase throughput, control instrument
failures, or exposure to fire often occur and can result in mechanical
failure. For example, furnace tubes start to sag or bulge, vessel
walls become distorted and develop cracks or blisters, and piping
becomes embrittled. Cyclic changes, including periodic shutdowns,
often accelerate these types of failures.
1.7.1 Incorrect or Defective Materials
Some failures in refineries are due to the initial installation of
incorrect or defective materials. Material mix-ups by suppliers are
the major cause of incorrect material. Positive material
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identification programs are designed to eliminate the expenses
associated with replacing incorrect materials.
Often, vendors may substitute a material they consider to be better
or equivalent to the material specified. Material substitution may
lead to corrosion problems in certain service environments. For
example, the substitution of a stainless steel fitting is not an
improvement over a carbon steel fitting in environments that lead to
pitting corrosion or SCC.
Substitution of castings for wrought or forged shapes often leads to
problems. Casting defects, such as shrinkage, sand holes, or
blowholes can create unforeseen cracking and corrosion problems.
Shrinkage cracks are often found in the thinner sections where the
cast metal cools faster. Sharp corners and abrupt changes in crosssectional area are stress raisers, and shrinkage cracks can occur at
such points. Molding sand trapped within the casting causes sand
holes. Blowholes are caused by gas trapped within the casting
during solidification. The sand and gas create crevices or holes
within the metal that may not be visible from the exterior of the
casting.
Discontinuities in wrought material are excellent crack initiators.
The discontinuities may be in the form of laminations and crevices,
which can cause hydrogen blistering in certain applications.
Shutdown situations may require the substitution of materials to
expedite repairs. Often, the correct material may not be obtained due
to long lead times and unreasonably high minimum quantity
purchase requirements. Intentional upgrading during shutdowns can
also lead to problems. For example, substitution of titanium tubes
for admiralty metal tubes may resolve corrosion problems at the
expense of vibration problems if care is not exercised. Due to the
lower wall thickness of titanium tubes, baffle spacing and tube hole
clearances should be checked to prevent titanium tube fatigue
failures.
1.7.2 Mechanical Fatigue
Mechanical fatigue is the failure of a component by cracking after
the continued application of cyclic stress. Below a definite stress
limit, cyclic stressing of a metal does not affect the material and no
cracking occurs regardless of the passage of time. This stress limit
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is called the endurance limit or fatigue limit. At stresses higher than
the endurance limit, a crack initiates and is propagated by continued
application of stress cycles. Eventually, the component fails, usually
from a single crack. Little deformation of the metal takes place, and
the failure appears to be brittle.
Generally, the endurance limit of steels is roughly 50% of the tensile
strength, while the endurance limit for nonferrous alloys ranges
from 35% to 50%. Fatigue properties are related to notch toughness.
Deep scratches, sharp corners, and weld intersections will lower
fatigue strength by locally concentrating stresses. Brittle steels are
more likely to fail by fatigue than ductile steels. High ductility
permits relief of concentrated stresses through plastic flow.
In refineries, a large number of failures have been attributed to
mechanical fatigue or, as discussed previously, corrosion fatigue.
Mechanical failures are common in reciprocating parts in pumps
and compressors and the shafts of rotating machinery.
Fatigue failures can be significantly minimized by eliminating stress
raisers. A radius should be used instead of sharp corners on rotating
or cyclically stressed parts. Stampings and other sharp-edged marks
should be avoided as well as cold straightening of bent parts that
will be subjected to in-service cyclic stress.
1.7.3 Corrosion Fatigue
Corrosion fatigue is a form of fatigue where a corrosion process,
typically pitting corrosion, adds to or promotes the mechanical
fatigue process. Pure mechanical or dry fatigue is a failure
mechanism that results from cyclic stress applied to a structural
component. Corrosion fatigue results in shorter life than would
occur with either dry fatigue or in the corrosive environment alone.
Dry fatigue takes the form of a single, stepped crack, but corrosion
fatigue usually takes the form of several or many cracks emanating
from the base of pits. Corrosion fatigue is thought to be a two-stage
process in which the first stage is the formation of corrosion pits,
and the second stage is the development of cracks. Failures are
associated with environments that favor pitting, probably because
pits act as stress raisers. Cracking by corrosion fatigue is
transgranular, without branching. Final failure is strictly
mechanical.
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Since the development of corrosion pits is the first step in corrosion
fatigue, mitigation of corrosion is the best approach to prevention.
Elimination of the cyclic stresses causing fatigue is the next best
approach. Shot peening, a process involving the cold working of a
metallic surface with a high-velocity stream of steel shot, introduces
residual compressive stresses a few mils deep in the surface.
Although the surface finish produced by shot peening is rougher
than that from machining or grinding, the resulting compressive
surface layer improves fatigue and corrosion fatigue resistance.
Stress relieving, corrosion inhibitors, and protective coatings have
also been successfully used to combat corrosion fatigue.
1.7.4 Cavitation Damage
Cavitation damage is caused by the rapid formation and collapse of
vapor bubbles in liquid at a metal surface as a result of pressure
variations. Calculations have shown that bubble collapse can
produce shock waves with impact pressures sufficiently high to
produce plastic deformation in most metals. In brittle metals,
cracking and metal loss occur as grains are torn out of the surface.
Corrosive conditions accelerate cavitation damage.
In refineries, cavitation occurs mostly on the backside of pump
impellers. Certain areas of piping components, such as elbows, also
can become subject to cavitation damage. Vibration can also lead to
cavitation. Damage is usually in the form of closely spaced pitting.
Cavitation works to harden the surface layer of most metals, which
can be detected by metallurgical examination of the damaged part.
Cavitation damage can be reduced by techniques similar to those
listed for erosion-corrosion. To mitigate cavitation damage, the
conditions causing cavitation must be eliminated.
1.7.5 Mechanical Damage
Mechanical damage to refinery equipment is a common cause of
failure. Damage to equipment can result from misuse of tools and
other equipment, wind damage, and careless handling of equipment
when moved or erected. Structural columns are normally designed
for compressive loading, and other types of loading may lead to
bending. Supports may be damaged when used as anchors for
winches. During earth-moving work, underground pipelines and
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electrical conduits may be damaged if they are not carefully located
and properly identified.
Flange faces and other machined seating surfaces may be damaged
when not protected with covers or when not handled with care.
Material may be thrown from truck beds in such a manner that it is
bent, crushed, or cracked. Tubes of heat exchanger tube bundles
may be crushed if the bundles are not lifted with proper slings.
Foundations, piping, or heat exchanger shells may be damaged
when an attempt is made to pull bundles without adequately
anchoring the shells.
Equipment and structures are normally designed to withstand
anticipated wind loads. During construction or repairs, however,
wind damage may result if components are not properly guyed or
reinforced. Loose sheets of metal, boards, and the like may be
blown about by high winds if they are not properly secured.
Wear or mechanical abrasion is a significant problem in refineries
and accounts for many failures. Catalyst movement in fluid catalytic
cracking units and coke handling in coking units are examples of
wear situations associated with refinery processes. Wear in pumps,
compressors, and other rotating machinery is commonly seen in the
refining industry. Abrasive wear can be classified into three types:
•
Gouging abrasion—A high-stress phenomenon that is likely to
be found under conditions of high-compressive stress coupled
with impact loads
•
Grinding abrasion—High-stress abrasion that pulverizes fragments of the abrasive substance that then becomes sandwiched
between mating metal surfaces
•
Erosion—A low-stress, scratching abrasive action.
Most parts designed for gouging abrasion service are made of some
grade of austenitic-manganese steel because of its outstanding
toughness coupled with good wear resistance. Austeniticmanganese steel along with hardenable carbon and medium-alloy
steels and abrasion-resistant cast irons are used to resist grinding
abrasion. Gouging and grinding abrasion are rarely seen in
refineries.
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Erosion is commonly observed, and the abrasive is likely to be gasborne (as in catalytic cracking units), carried by liquid (as in
slurries), or gravity-pulled (as in catalyst transfer lines or coke
handling equipment). Because velocity and kinetic energy of
abrasive particles are associated, the severity of erosion typically
increases as a function of the velocity.
The angle of impingement also influences the severity of the attack.
A metal’s abrasion resistance may be influenced by whether it is
ductile or brittle. Most abrasion involved with hydrocarbon
processing is of the erosion type.
A number of alloys are available for abrasive service in the form of
wrought alloys, sintered metal compacts, castings, and hardsurfacing materials. They can be classified in descending order of
abrasion resistance and ascending order of toughness, as follows:
•
Tungsten carbide and sintered carbide compacts
•
High-chromium cast irons and hardfacing alloys
•
Martensitic irons and hardfacing alloys
•
Austenitic cast irons and hardfacing alloys
•
Pearlite steels
•
Ferritic steels
•
Austenitic steels, especially 13% manganese type.
Since toughness and abrasion resistance are likely to be opposing
properties, considerable judgment is required in deciding a suitable
material. Hardness is often thought to be a property indicative of
good wear resistance. It must, however, be considered with
discretion when evaluating an alloy’s suitability in abrasive
situations. Hardness should only be considered after its relation to a
given service has been proven. Simple and widely used hardness
tests, such as Brinell or Rockwell, are not effective in determining
the hardness of microscopic constituents that are important to good
wear resistance.
1.7.6 Overloading
Overloading occurs when loads in excess of the maximum permitted
by design are applied to equipment. Hydrostatic testing of vessels
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can overload supporting structures due to the excess weight applied.
Excessive bending stresses may be induced in vessel shells when
pipe support brackets are attached. Addition of piping to existing
pipe supports, or piping that is left overhanging on supports, may
present overloading problems. Overloads can also occur where
metal members have been weakened as a result of corrosion, wear,
fire, or change in shape or position. Supports are sometimes bent or
shifted in position by accidents or through use as hitches.
Thermal expansion and contraction cause many overloading
problems, unless flexible connections are properly provided. Piping
subject to thermal expansion may force a centrifugal pump or steam
turbine out of alignment and warp the shaft, unless the pipe is
anchored near the equipment. Failures result from fatigue stresses
that build up at supports, piping, and equipment in which sharp
corners exist and in which anchoring attachments are undersized for
vibration loading.
There are other areas where overloading occurs. Uneven or overtightened bolting may crush gaskets between flanges. Furnace
stacks, flare stacks, or similar structures are subject to overstressing
by unevenly tightened guy lines. Failure of equipment may result
where wooden supports decay or burn. Severe impact loads occur
in machinery, such as compressors, when bolts become loose or
defective parts fail. Excessive loading is usually apparent because
of visible distortion, such as change of shape or change of position.
Typical evidence of overloading includes the following:
•
Sagged or bent support beams
•
Cracked welds
•
Slipped bolts on bolted surfaces
•
Excessive springing of piping as it is being disconnected
•
Repeated bolting failures
•
Loose guy lines.
1.7.7 Overpressuring
Overpressuring may be defined as the application of pressure in
excess of the maximum allowable working pressure of the
equipment. With low excess pressure, there is little chance of
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damage occurring. When excess pressures are high, failures causing
loss of life and property can occur. Overpressuring causes buckling,
bulging, ruptures, and splits. It develops in a number of ways,
including:
•
Excess heat, which develops as a result of abnormal operating
conditions or upsets. Failure of controls or loss of flow, which
has happened in furnaces, can also cause excess heat.
•
Blocking off equipment that is not designed to handle full process pressure
•
Hydraulic hammer or resonant vibration
•
Inadequate or defective vents and pressure relief valves
•
Thermal expansion of trapped liquid
•
Expansion of freezing ice plugs.
1.7.8 Brittle Fracture
Brittle fracture is the most pronounced mechanical effect of low
temperature on steel. It is a loss of ductility in which the steel is
referred to as having low notch toughness or poor impact strength.
The loss of impact strength at lower temperatures can result in
brittle fracture not only upon actual impact loading, but also under
conditions of more or less constant stress.
Brittle fractures, unlike ductile failures, occur without warning and
cracks tend to propagate with a loud report. There is little indication
of bulging or distortion and, once a crack starts in a pressure vessel,
it will very likely continue through more than one shell plate. Lack
of warning and the rapid and extensive propagation of cracks
account for the fact that such failures are often catastrophic. Some
brittle failures of tanks and pressure vessels have occurred during
hydrostatic or pneumatic testing. For this reason, it is generally the
policy to refrain from testing while ambient temperatures are low,
particularly if the testing medium is cold. In any case, the test
pressure is applied as slowly as practical to avoid sudden increases
in stress.
Brittle fracture can be recognized by several characteristics:
•
Cracks propagate at high speed with a loud report.
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•
There is almost a complete lack of ductility in the metal.
•
The fractured surface has a characteristic chevron or herringbone
appearance, with the apexes of the chevrons pointing to the
origin of the fracture.
To measure impact strength, specimens of test material are heated or
cooled to different test temperatures and individually struck with a
falling pendulum. The absorbed energy of each test is plotted
against the specimen test temperature. An important feature of the
energy versus temperature plot is the temperature range where
impact energy rapidly decreases and reaches a low value. This is the
material’s ductile-to-brittle transition temperature and, among
steels, may vary from above room temperature to very low
temperatures. A low transition temperature is indicative of a
material’s ability to resist brittle fracture.
Among refinery metals and alloys, certain carbon and low-alloy
steels have high enough transition temperatures so that special
precautions must be taken during equipment pressurization. If these
steels are at temperatures below their transition temperature, notch
toughness will be low and when pressure is applied, a brittle failure
is likely to occur. In contrast, austenitic stainless steels, nickel
alloys, copper alloys, and aluminum alloys retain their ductility at
very low temperatures.
1.7.9 Creep
Creep is a high-temperature mechanism in which continuous plastic
deformation of a metal takes place while under applied stresses
below the normal yield strength. Creep strengths are usually
expressed as the stress which produces a strain rate of 1% in either
10,000 hours or 100,000 hours at a given metal temperature. Creep
strength data are the controlling mechanical property when metals
are exposed for continuous service at high temperatures, such as
with furnace tubes and supports. Creep failures are often found in
the form of badly sagged furnace tubes. For steels, creep becomes
evident at temperatures above 650F (343C).
1.7.10 Stress Rupture
Stress rupture is the time it takes for a metal at elevated temperature
to fail under applied stresses below its normal yield strength. Stress
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rupture data are usually expressed as the stress which causes rupture
in either 100, 1000, 10,000, or 100,000 hours at a given metal
temperature. Actually, stress rupture tests are accelerated creep tests
which have been carried to failure. Stress rupture data are used
extensively in the design of furnace tubes. For carbon steel, the
long-term stress to cause rupture at 900F (482C) is 11,500 psi
(79.5 Mpa). This can be compared to the short-term tensile strength
of 54,000 psi (373 Mpa) for steel at 900F (482C).
Grain size and alloy composition are two factors that influence
creep and stress rupture. Coarse grain size materials possess the
greatest creep strength at elevated temperatures. Slight changes in
composition often alter the creep strength appreciably, with carbideforming elements being the most effective in improving the rupture
strength. The relative magnitude of the effects of small changes in
stress and temperature are important to understand. For materials
operating in the creep range, small changes in temperature above
design can drastically reduce service life. Small pressure changes
are less significant.
Stress rupture failures in the refinery are usually associated with
fired heater tubes and fired boilers. Most of these are caused by
overheating and local hot spots in the furnace, resulting from faulty
burners, inadequate control of furnace temperature, and coke or
scale deposits within the tubes. Bulging or hot spots are signs of
impending failure. In the case of hydrogen-producing steam
methane reforming furnaces, improper catalyst loading can result in
tube hot spots and ruptures.
1.7.11 Thermal Shock
Thermal shock occurs when large and non-uniform thermal stresses
develop over a relatively short time in a piece of equipment due to
differential expansion or contraction caused by temperature
changes. If movement of the equipment is restrained, this can
produce stresses above the yield strength of the metal. In refineries,
thermal shock is caused by occasional, brief flow interruptions or
during a fire.
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1.7.12 Thermal Fatigue
Thermal fatigue differs from thermal shock in that the rate of
temperature changes experienced is much greater and the magnitude
of the temperature gradient is much less. Every time a processing
unit is started up or shut down, thermal stresses set up in equipment.
Repeated application of thermal stresses can lead to progressive
cracking, not unlike that of pure mechanical fatigue. Coke drums are
an example of refinery pressure vessels subject to thermal cycling
and associated thermal fatigue cracking. Bypass valves and piping
with heavy weld reinforcement on reactors in cyclic temperature
service are also prone to thermal fatigue.
1.8 Other Forms of Corrosion
Other forms of corrosion experienced by refinery equipment result
from boiler feed water, steam condensate, cooling water, and fuel
ash.
1.8.1 Boiler Feed Water Corrosion
Boiler feed water for steam generation must be treated to protect
boilers and auxiliary equipment against corrosion during operation.
Low-temperature corrosion problems occur in the reheat system,
deaeration equipment, feed water piping and pumps, stage heaters,
and economizers. The primary causes of corrosion are dissolved
oxygen and low-pH conditions from the presence of acidic
constituents.
Even small concentrations of oxygen can cause serious pitting
corrosion. Oxygen enters with makeup water due to air leakage on
the suction side of pumps or as a result of the breathing of supply
water tanks. It can be removed by mechanical deaeration, followed
by chemical treatment with catalyzed sodium sulfite. For boilers
operating above 1000 psi (6890 kPa), hydrazine is used instead of
sodium sulfite. Neutralization is usually accomplished with soda
ash or with organic neutralizers, such as morpholine or
cyclohexylamine.
Deposition of various materials on boiler surfaces can not only
cause failure by overheating, but also by highly localized corrosion.
As mentioned earlier, caustic concentrates under porous deposits,
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resulting in caustic corrosion, gouging, and caustic embrittlement.
Even when demineralized makeup water is used, a coordinated pH/
phosphate treatment may be required to control caustic corrosion.
In certain, critical boiler applications, only volatile treatments can
be used because absolutely no boiler water solids can be tolerated.
1.8.2 Steam Condensate Corrosion
Steam condensate corrosion is caused by dissolved oxygen and
carbon dioxide. Oxygen corrosion in condensate systems occurs in
the form of pitting. In contrast, carbon dioxide corrosion usually
takes the form of uniform metal loss. Thinning and longitudinal
grooving of the lower portion of piping and heat exchanger tubes
points to carbon dioxide corrosion as the most probable cause. CO2
enters the steam condensate system either as dissolved gas or as
bicarbonate or carbonate alkalinity in boiler makeup water.
Dissolved CO2 normally will be removed by properly operated
deaeration equipment. However, external treatment methods are
required to reduce the alkalinity of the makeup water. Condensate
corrosion can be controlled by injecting filming amine corrosion
inhibitors, usually in conjunction with ammonia or organic
neutralizers, such as morpholine or cyclohexylamine.
1.8.3 Cooling Water Corrosion
Most refinery cooling water systems are the open recirculating type,
with mechanical draft cooling towers. Cooling is by evaporation of
a portion of the water, which concentrates the minerals in the
circulating water. Makeup water replaces water losses from
evaporation. Since makeup water is often scarce and expensive,
many cooling water systems operate at 2 cycles to 4 cycles of
concentration or higher.
Intimate contact of cooling water with air can create a multitude of
corrosion problems. Airborne contaminants, such as hydrogen
sulfide, ammonia, sulfur dioxide, fly ash, or dirt, are scrubbed from
the air in the cooling tower and can contribute to corrosion. The
concentration of dissolved minerals, such as chlorides and sulfates,
increases the conductivity of cooling water as well as the tendency
toward crevice corrosion beneath deposits. Relatively high
temperatures also increase the potential for corrosion.
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Cooling water corrosion normally is not a problem with inhibited
admiralty metal tubes or with titanium tubes. However, these can
foul if scale formation is not controlled. Cooling water corrosion
can seriously damage carbon steel equipment, such as piping, heat
exchanger tubes, channels, channel covers, and tubesheets.
Corrosion of carbon steel heat exchanger tubes is especially
troublesome for several reasons, including:
•
Even relatively low corrosion rates of 1 mil to 2 mils per year
can form enough corrosion products in the form of tubercles on
the tube wall to interfere with water flow.
•
Scale formation on tube walls is accelerated by the presence of
corrosion products, interfering further with water flow.
•
The resultant decrease in water flow can raise the temperature of
the water to the point where it boils in part of the bundle.
•
Under the above conditions, increased corrosion leads to premature tube failures, sometimes within a few months of operation.
Maintaining small concentrations of inorganic corrosion inhibitors
in the water controls corrosion in open recirculating cooling water
systems. These inhibitors retard corrosion through the formation of
protective oxide films on carbon steel. Common examples of
inhibitors include various combinations of chromate,
polyphosphates, and zinc compounds. Recently, various organic
inhibitors have been combined with certain inorganic materials to
meet regulations that limit air and water-borne chromate discharges.
Refineries that rely on brackish water or seawater for cooling should
consider aluminum brass, copper-nickel, or titanium tubes. These
are normally rolled into carbon steel tubesheets, which are solid or
clad with aluminum bronze, Monel (70% Ni, 30% Cu), or titanium
on the water side. Monel 400 is an alternative tubesheet material
and can be used to clad or weld-overlay components in salt-water
service.
1.8.4 Fuel Ash Corrosion
Fuel ash corrosion can be one of the most serious operating
problems with fired boilers and hydrocarbon furnaces. All fuels,
except natural gas, contain certain inorganic contaminants which
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leave the furnace with the products of combustion. These products,
which include various combinations of vanadium, sulfur, and
sodium compounds, deposit on metal surfaces, such as superheater
and convection tubes, and upon melting can cause severe liquidphase corrosion.
In particular, vanadium pentoxide (V2O5) vapor reacts with sodium
sulfate (Na2SO4) to form sodium vanadate (Na2O 6V205). The
latter compound reacts with steel, forming a molten slag, which runs
off and exposes fresh metal to attack. Corrosion increases sharply
with increasing temperature and vanadium content of the fuel. If the
vanadium content in the fuel oil exceeds 150 ppm, the maximum
tube wall temperature should be limited to 1200F (648C).
Between 20 ppm and 150 ppm vanadium, maximum tube wall
temperatures can be between 1200F (648C) and 1550F (843C),
depending on sulfur content and sodium/vanadium ratio of the fuel
oil.
In general, most alloys are likely to suffer from fuel ash corrosion.
However, alloys high in both chromium and nickel provide the best
resistance toward this type of attack. Sodium vanadate corrosion
may be reduced by firing boilers and heaters with low excess air
(less than 1%) to minimize formation of sulfur trioxide in the
firebox and limit the amount of vanadium pentoxide present in the
melting slag.
Additives can be helpful in controlling fuel ash corrosion,
particularly in conjunction with low excess air firing. The
effectiveness of additives varies, with the most useful additives
based on organic magnesium compounds. Additives raise the
melting point of fuel ash deposits and prevent formation of sticky
and highly corrosive films. With additives, a porous and fluffy
deposit layer is formed, which can readily be removed.
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Corrosion and Other Failures
References
1.
2.
ASTM D664-95, “Standard Test Method for Acid Number of Petroleum Products
by Potentiometric Titration” (West Conshohocken, PA: ASTM, 1995).
ASTM A193/A193M-99, “Standard Specification for Alloy-Steel and Stainless
Steel Bolting Materials for High-Temperature Service (West Conshohocken, PA:
ASTM, 1999).
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Chapter 2:Crude Distillation and
Desalting
Objectives
Upon completing this chapter, you will be able to do the following:
•
Identify constraints influencing the production of refinery
products
•
Identify and describe the components of crude oil
•
Discuss the development of a crude oil distillation curve
•
Describe the relationship between the weight of a compound and
the temperature at which it boils
•
Discuss the need for pretreatment of crude oil prior to distillation
•
Identify and describe three desalting methods
•
Describe the preflash process
•
Identify the major pieces of equipment found in crude distillation units and describe the flow of crude oil through a distillation
unit
•
Describe the separation process of vapors and liquids in the
atmospheric distillation column
•
Define reflux and its significance to the distillation process
•
Discuss the purpose of reboilers in distillation
•
Identify the products of the primary flash column and their
destinations
•
Identify the function of the stripper and describe the process of
separating vapor from the liquid stream
•
Discuss the process that takes place in the vacuum distillation
column and identify the products produced
•
Identify crude unit operating conditions that promote corrosion
in crude distillation units
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•
Select materials of construction for crude unit equipment and
piping that protect the unit from corrosion
•
Discuss corrosion control methods used to reduce the severity of
attack in the crude unit overhead circuit
•
Identify several methods used to evaluate the effectiveness of
crude unit corrosion control programs.
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2.1 Introduction
The basic raw material for a refinery is crude oil. Generally, refinery
processes produce relatively few products. See Figure 2.1.
Figure 2.1 Saleable Refinery Products
In reality, refinery operations are very complex. The degree of
oversimplification presented in Figure 2.1 becomes apparent when
degrees of constraint are examined. Constraints that have an impact
on refinery operations include:
• Sources of crude oil
•
Composition of crude oil
•
Purchase price of crude oil
•
Market demand for each product
•
Sale price of each product
•
Configuration of the refinery
•
Cost of production of each product.
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2.1.1 Sources of Crude Oil
Pipeline networks and marine tanker transportation transfer crude
oil to refineries from sources around the world. Crudes are often
classified according to their point of origin. For example, in the
United States, crude oils are classified as paraffin-base, asphaltbase, naphthene-base, or mixed-base. Some crude oils from the Far
East are known as aromatic-base oils. Although crudes from
different sources display physical characteristics that vary widely,
the chemical compositions of crude oils are surprisingly uniform.
2.1.2 Composition of Crude Oil
Crude oil consists of two major groups of components:
•
Hydrocarbon constituents
-
•
Normal paraffins
Isoparaffins
Cycloparaffins (naphthenes)
Olefins
Aromatics
Non-hydrocarbon constituents
-
Sulfur compounds
Oxygen compounds
Nitrogen compounds
Porphyrins
Metallic compounds
Salts (NaCl)
Water
The hydrocarbon constituents are by far the bulk of the crude oil.
The distribution of the several classes of hydrocarbons can
contribute to or adversely affect the production of the saleable
products.
The non-hydrocarbon constituents of crude oil are present in much
smaller quantities, but can be most troublesome. The sulfur
compounds cause not only corrosion in refinery equipment but, if
not removed, cause corrosion in equipment using the saleable
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refinery products. The remaining non-hydrocarbon components of
crude oil can also cause corrosion as well as catalyst poisoning and/
or gum formation in gasoline.
2.1.3 Remaining Constraints
The remaining constraints—purchase price of crude oil, market
demand for each product, sale price of each product, configuration
of the refinery, and cost of production of each product—are largely
economic factors. These will not be discussed in detail; however, it
is apparent that economic balances are required to determine
whether certain crude products should be sold as is or further
processed to produce products having greater value. Computer
programs are modeled so that each of these constraints can be varied
to reflect the optimum production and profit goals of the refiner.
2.2 More about Crude Oil Composition
From the foregoing examination of crude oil composition, it is
obvious crude oil is not a single chemical compound. Instead, it is a
mixture of thousands of chemical compounds. The nature and
characteristics of this mixture can be demonstrated by comparing
the behavior of water with that of crude when heated. See Figure
2.2.
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Figure 2.2 Boiling Temperature of Water (212F[100C])
When a pot of water is heated to 212F (100C), the water starts to
boil. Eventually, as long as the heat is continually applied, all the
water will boil off. A thermometer in the pot would still register
212F (100C) just before the last bit of water boiled off. That’s
because the chemical compound H2O boils at 212F(100C).
The same pot filled with a medium weight crude oil is heated. As
the temperature reaches 150F (66C), the crude oil starts to boil.
Keeping the flame under the pot to maintain the temperature at
150F (66C), the crude will stop boiling after a while. When the
temperature is increased to 450F (232C), the crude starts to boil
again and after a while, as long as the temperature remains 450F
(232C), the boiling stops.
By increasing the temperature, more and more crude oil would boil
off. See Figure 2.3.
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Figure 2.3 Boiling Temperatures of Crude Oil
The compounds that boil at a temperature below 150F (66C)
vaporized during the first heating, the compounds that boil at
temperatures between 150F (66C) and 450F (232C) vaporized
during the second heating, and so on. This information can be used
to develop a distillation curve, which is a plot of temperature on the
y-axis and the percent evaporated on the x-axis. See Figure 2.4.
Figure 2.4 Crude Oil Distillation Curve
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Crude Distillation and Desalting
Each type of crude oil has a unique distillation curve that
characterizes the kinds of chemical compounds present in that
crude. In general, the more carbon atoms in a compound, the higher
the boiling temperature. See Table 2.1.
Table 2.1: Number of Carbon Atoms vs. Boiling Temperature
Compound
Formula
Propane
Butane
Decane
C3H8
C4H10
C10H22
Boiling
Temperature
-44F (-42.2C)
31F (-0.6C)
345F (173.8C)
The character of crude oil can also be described by lumping certain
compounds into groups called fractions. A fraction or cut is the
generic term used for all compounds that boil between two
temperatures or cut points. A typical crude oil has the fractions
shown in Table 2.2.
Table 2.2: Typical Crude Oil Fractions
Temperatures
90F (32.2C)
90F to 220F (32.2C to 104C)
220F to 315F (104C to 157.2C)
315F to 450F (157.2C to 232C)
450F to 800F (232C to 426C)
800F and higher (426C and higher)
Fraction
Butanes and lighter
Gasoline
Naphtha
Kerosene
Gas oil
Residue
The light crudes tend to have more gasoline, naphtha, and kerosene.
The heavy crudes are composed of more gas oil and residue. In
general, the heavier the compound, the higher the boiling
temperature.
Another method of characterizing crude oil and petroleum products
is by weight or gravity. Gravities measure the weight of a
compound. Chemists always use a measure called specific gravity,
which relates everything to water. The specific gravity of any
compound is equal to the weight of some volume of that compound
divided by the weight of the same volume of water. The following
equation illustrates this definition:
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Specific gravity =
weight of the compound
weight of water
However, the popular measure of gravity in the oil industry is API
gravity, which is measured in degrees. The formula for API gravity
is:
API =
141.5
specific gravity
– 131.5
The higher the API gravity, the lighter the compound. The reverse
is true for specific gravity. See Table 2.3.
Table 2.3: Typical Gravities
Heavy crude
Light crude
Gasoline
Asphalt
Water
Specific Gravity
0.95
0.84
0.74
0.99
1.00
API Gravity
18
36
60
11
10
The distillation curves for three domestic crudes and two foreign
crudes are shown in Figure 2.5.
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Figure 2.5 Distillation Curves for Certain Crude Oils
As mentioned previously, some crudes have more light fractions and
some more heavy fractions. They all have different prices.
Depending on product demands and the equipment in a refinery,
some crudes will be more suitable and economically attractive than
others.
The terms sweet and sour shown on some of the curves in Figure 2.5
refer to the sulfur content of the crudes. Typically, crudes containing
0.5% sulfur or less are referred to as sweet crudes. Sour crudes
contain 2.5% or more sulfur. In between these limits are
intermediate sweet or intermediate sour crudes.
In the petroleum refining process, the crude unit is the initial stage
of distillation of the crude oil into useable fractions, either as end
products or feed to downstream units. It is called upon to handle a
variety of crude oil compositions as well as produce varying
amounts of fractions to support the refiner’s goals, which often
change to accommodate seasonal demands or fluctuating prices.
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2.3 Crude Oil Pretreatment
Although crude distillation is the first major step in refining,
pretreatment of the crude distillation feed is almost always required
to minimize downstream corrosion. Crude oil as produced in the
field usually contains salt water. This salt water can result in
corrosion by hydrogen-ion attack and hydrogen chloride attack. In
addition, various sulfur compounds can form hydrogen sulfide,
which is also a highly corrosive agent.
Sulfur exists in crude oil as elemental sulfur, dissolved hydrogen
sulfide (H2S), or as sulfur in complex molecular combination with
hydrocarbons. The boiling points at atmospheric pressure of these
compounds range from 40F to 320F (4.4C to 160C). As crude
oil is heated from 300F to 430F (149C to 221C) or to higher
temperatures, elemental sulfur reacts to form H2S. The organically
bound sulfur compounds are not transformed into H2S until higher
temperatures are reached. Two measures are generally used to cope
with sulfur and sulfur compounds present in crude oil. They are:
1. H2S is removed in gaseous form early in the refining process.
2. The organically bound sulfur compounds continue through
the refining process and are separated with the refinery product whose boiling range coincides with that of the sulfur
compounds. For example, those sulfur compounds boiling
between 100F to 200F (37.8C to 93C) will be removed
from the main refinery stream in the gasoline fraction.
Depending upon the specifications of the gasoline, the sulfur
compounds must be removed by specific finishing processes,
such as the Merox process. Other products require other treatments.
2.4 Desalting
To minimize the adverse effects of impurities found in crude oils,
the refiner often washes the crude oil with water and uses a desalting
vessel to remove the added water and most of the inorganic
contaminants prior to distillation in the crude unit. Water, chlorides
such as NaCl, and solids are removed by one or more desalting
methods. See Figure 2.6.
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Figure 2.6 Desalting Methods
The desalting process begins by adding hot water to the crude oil
and heating the mixture to between 200F and 300F (93C to
149C) at pressures between 50 psi and 250 psi. The temperature
should be low enough to prevent vapor loss. The total stream is then
sent to a vessel sufficiently large to permit the formation of a
desalted crude oil layer and a water layer containing the chlorides,
water, and solids. This procedure is illustrated as Method 1 in
Figure 2.6. The remaining two methods are refinements of Method
1.
Method 2 imposes a high-frequency electric field across the settling
tank. Method 3 substitutes a vertical packed column for the settling
tank of Method 1. Both of the latter two refinements are designed to
promote coalescence and separation of the oil and water into two
distinct layers. Chemical agents are added in Method 1 and Method
2 to break emulsions of oil and water and promote formation of a
relatively clean interface between the two layers.
Several major variables influence the effectiveness of the desalter
operation, including:
•
Crude oil properties—Desalters rely on the density difference
between oil and water. Therefore, lower gravity (higher den-
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sity), higher viscosity crudes make it more difficult to separate
water from the crude.
•
Desalting temperature and pressure—The upper temperature
limit of 300F (149C) is to avoid vaporization of the crude oil
in the desalter or to prevent damage to the electrical grid
insulator bushings.
•
Residence time—Adequate residence time is essential for oilwater separation. Heavier crudes require longer residence time
because the gravity difference between the oil and water is
reduced. For low-gravity crudes, the required water residence
time can be two hours. Chemical emulsion breaker selection
may have a significant effect on oil undercarry in the water,
which is caused by inadequate residence time.
•
Wash water quality and rate—Variables in water quality,
particularly pH can affect the effectiveness of desalting and the
transport of water and ammonia into the crude or oil into the
desalter brine water. Sufficient added water must be provided to
ensure good coalescence of the water in the crude. The refiner’s
needs, environmental requirements, and availability of reusable
process waters determine the source of the desalter wash water.
However, the purer the water, the easier it is to wash the crude.
The volume of water used can be from 3% to 10%, with typical
usage at approximately 5% based on the total crude charge.
Lowering the wash rate below 3% of the total charge reduces the
rate of coalescence, making water removal more difficult. A low
water rate combined with high mixing energy will degrade
desalter performance.
•
Wash water mixing—A controllable mixing is required to ensure
the added water is dispersed well so that it can combine with the
contaminants in the crude oil. A mixing valve with adjustable
pressure drop is typically used for mixing. The wash water
injection site may vary, but is normally located in one or more
places between the raw crude charge pump and the mix valve.
Typically, some of the wash water is injected upstream of the
crude preheat heat exchangers to prevent boil-dry of brine droplets on heat transfer surfaces. Injecting desalter water into the
suction of a crude pump is not recommended because this
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mixing cannot be controlled. Over-mixing can prevent adequate
water coalescence.
2.5 Preflash
The desalted crude still contains dissolved H2S and other sulfur
compounds. H2S must be removed early from the refinery
equipment train to avoid corrosion of the equipment downstream.
Somewhat incomplete removal of the H2S is achieved by further
heating the desalted crude and expanding the gas-liquid mixture in a
vapor-liquid separator. Figure 2.7 illustrates this method.
Figure 2.7 Preflash Method
The light gases containing the H2S are routed to a hydrogen sulfide
removal unit or to the plant gaseous fuel system. The liquid phase is
sent to the crude distillation section, which is the first major unit of
the refinery.
2.6 Crude Distillation Unit
As mentioned previously, the function of this unit is to separate the
several cuts of the crude oil mixture for further processing in
downstream refinery units. The major pieces of equipment are four
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fractional distillation columns, pumps, heaters, and heat exchangers.
See Figure 2.8. The four fractionators are the:
•
Primary flash column
•
Atmospheric distillation column
•
Stripper
•
Vacuum distillation column
Crude Distillation Unit
Neutralizer
Filming Amine Inhibitor
Crude Preheat
Gases
Cooling
H2O
Light
Liquids
Sour Water
Water Recirculation
Dist.
Naphtha
Naphtha
Reflux Naphtha
Kerosene
Desalted
Crude
30-45 psig
Heater
Atmospheric Distillation
Primary Flash
Caustic
(Optional)
600-7000F
700 F +
Max. Vacuum
Steam
Vacuum Distillation
Diesel Oil
500-600F
30-45 psig
Light
Medium
Heavy
Gas Oils
Superheated
Steam
Residue
to Coker
or
Asphalt
Heavy Components
Figure 2.8 Crude Oil Distillation Unit
A distillation column is a vertical cylindrical pressure vessel
equipped internally with horizontal trays, which provide intimate
mixing of liquid and vapor. A temperature differential is caused to
exist from top to bottom of the column; the top of the column is at a
lower temperature than the bottom. The multi-component feed
enters the column, with the heavier liquid descending to the bottom
of the column and the lighter vapors moving to the top.
Intimate mixing of rising vapor and descending liquid occurs on
each tray. The mixture of liquid and vapor on each tray approaches
equilibrium at the temperature of the mixture on that tray. As a
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result, the lighter components become increasingly concentrated in
the vapor phase on each tray as the vapor flow rises to the top of the
column. The heavier components become increasingly concentrated
in the liquid phase on each tray as the liquid flow descends to the
bottom of the column.
To understand this concept, visualize two recycling streams flowing
within the column. The vapor stream consisting of lighter and
heavier components rising and the liquid stream consisting of
heavier and lighter components descending. Due to the temperature
difference which exists from top to bottom of the column, i.e., the
top temperature is lower than the bottom, the equilibrium mixture
on each tray becomes richer in the lighter components and leaner in
the heavier components as the two passing and commingling
streams flow upward and downward in the column.
Frequently, distillation columns are equipped with overhead
condensers. The overhead vapor is partially or totally condensed by
heat exchangers with a coolant. A portion of the condensed liquid,
called reflux, is returned to the top tray of the column, decreasing
the temperature of the top tray and increasing the temperature
differential from top to bottom of the column. This increased
temperature differential causes an increased liquid flow from tray to
tray down the column. The flow reinforces the tendency of the
lighter components to be concentrated in the rising vapors and the
heavier components to be concentrated in the descending liquids.
Distillation columns are also frequently equipped with bottoms
reboilers. The bottom liquid from the column is sent to a reboiler
and heated. The addition of heat drives more of the lighter
components into the vapor phase and reintroduces this vapor phase
under the bottom tray. This increases the vapor flow up the column,
reinforcing the internal vapor flow.
A simpler way of visualizing the tray-to-tray concentration of light
components in the vapor phase and heavier components in the liquid
phase is to refer once again to Figure 2.3, Boiling Temperatures of
Crude Oil, and Figure 2.4, Crude Oil Distillation Curve. Assume
that the beakers being heated are closed, confining the vapor phase
in contact with the liquid. Further assume that instead of being
heated, the beakers are cooled. A portion of the heavier components
in the vapor phase will start condensing, leaving the vapor phase
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richer in light components. This process parallels in a gross manner
the action occurring on each tray of the distillation column.
2.7 Operation of a Crude Distillation Unit
Overall operation of petroleum refineries is not static but is varied to
meet product demand. For example, operation during spring and
summer might tend to maximize motor gasoline production, while
during fall and winter emphasis might be on fuel oil production.
Obviously, operation of the crude distillation unit is varied to
coincide with the desired product mix.
Desalted crude oil is fed to the primary flash column. The overhead
products, consisting of butane and lighter components might be sent
to a light ends treating unit for H2S removal and recovery of
liquefied petroleum gas (LPG) or sent to the refinery fuel system.
Light naphtha in the column liquid overhead may be combined with
naphtha from the atmospheric column and sent to a naphtha splitter.
The bottom product of the primary flash column is heated and fed to
the distillation column. The overhead product from the distillation
column, consisting largely of naphtha, is routed with other naphtha
streams to a naphtha splitter for production of naphtha as a saleable
product or as feed to downstream process units.
The stripper acts as an auxiliary to the atmospheric distillation
column. Since the individual sections (each section is equipped
with four to six trays) of the stripper are relatively short, they are
stacked one above another. Each section, however, acts as an
individual unit. Liquid is withdrawn from selected trays of the
distillation column and fed to a section of the stripper. For example,
kerosene is drawn off the upper part of the column, sent to the
stripper and then to hydrotreating or fuel oil product storage. Diesel
is drawn off the middle of the column, sent to the stripper, and then
to hydrotreating or hydrocracker feed or to diesel or fuel oil product
storage. Atmospheric gas oil is drawn off the lower portion of the
column, stripped, and sent to fluid catalytic cracking feed or to
hydrotreater feed.
Steam is injected under the bottom tray of each section in the
stripper; this steam plus the rectifying action of the trays promotes
separation of the more volatile components. The vapor from the top
tray of each section is returned to the distillation column. The liquid
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stream is removed as a stripped sidestream product by being
withdrawn from the bottom of each section.
The overhead product of the distillation column consisting of
components in the naphtha boiling range is combined with naphtha
from the stripper and sent to storage or to a downstream processing
unit. The bottoms from the distillation column, consisting of the
heaviest components of the crude oil, are routed to the vacuum
distillation column.
The boiling point of the heaviest cut obtainable at atmospheric
pressure is limited by the temperature at which these heavy
components start to decompose or crack. For the manufacture of
lubricating oils, further fractionation without cracking is desirable.
This is accomplished in the vacuum distillation column. This
column is operated at a sub-atmospheric pressure, thereby
permitting separation of the desired cuts at temperatures below
660F (349C), which is the temperature at which cracking occurs.
Feed and bottom residue stream temperatures are kept below the
cracking temperature. A further aid to separation results from
addition of superheated steam to the bottom of the column, thus
lowering the partial pressure of the hydrocarbons and promoting
separation.
The products from the vacuum distillation column are:
•
Gas oil as a top product
•
Side streams of various weight lube oils or gas-oils, depending
on the desired final product mix
•
A bottoms product which can be used as feed for coke or asphalt.
Of all the units in a refinery, the crude distillation unit is required to
have the greatest flexibility in terms of variable composition of
feedstock and desired range of product.
Auxiliary equipment of a crude distillation unit consists of:
•
Fired heaters
•
Steam heaters
•
Water-cooled heat exchangers
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•
Vacuum compressors (to maintain the vacuum on the vacuum
distillation column)
•
Pumps
•
Piping.
Direct-fired heaters are necessary to attain the high temperatures
required. These fired heaters are subject to corrosion and other
material problems on both the product side and in the firebox.
2.8 Corrosion in Crude Distillation Units
Crude oil is predominantly a combination of carbon and hydrogen
compounds, which are not in themselves considered corrosive to
carbon steel. Unfortunately, the impurities found in most crude oil
can be highly corrosive under crude refinery operating conditions.
The majority of the equipment in a crude unit is made of carbon
steel regardless of whether the crude oil is sweet or sour. The use of
carbon steel is possible because at temperatures below about 232C
(450F), except for the preflash and atmospheric column overhead
systems, the streams are essentially non-corrosive to carbon steel.
However, where temperatures exceed 232C (450F), problems
with high-temperature sulfur attack and naphthenic acid corrosion
may occur. (See Chapter 2 for more information). The most
significant sulfur-related corrosion problems are caused by H2S
below the water dew point and above 260C (500F). In sour units,
a crude TAN (total acid number) of 1.0 (mg KOH/g) can cause
naphthenic acid corrosion. In sweet units, a TAN of 0.5 may be high
enough to cause corrosion (See Chapter 2 for more information).
In the overhead system, the formation of acidic deposits of
condensates occurs below about 120C (250F) and often requires
the use of one or more highly alloyed materials. (See Chapter 2 for
more information). Organic chlorides result from the carryover of
chlorinated solvents used in the oilfields, or they can be picked up
by the crude during transportation in contaminated tanks or lines.
Organic chlorides are not removed in the desalters and may
decompose later in the heaters, producing hydrochloric acid. (See
Chapter 2 for more information).
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Major equipment and systems in the crude unit that may experience
corrosion include:
•
Columns
•
Exchangers and piping
•
Fired heaters.
2.8.1 Columns
Crude unit columns experiencing operating conditions that may lead
to various forms of corrosion include:
•
Preflash column
-
•
Atmospheric column
-
-
•
Top zone operates near or below the dew point
Inlet temperature is about 260C (500F), which can lead
to sulfur corrosion
Feed temperatures of 365C (690F)
Feed contains fairly large amounts of HCl and H2S
Introduction of cold reflux at the top of the column can
cause localized condensation and corrosive conditions to
carbon steel.
Lower two-thirds to three-fourths of the column is
susceptible to high-temperature sulfur corrosion.
Area of feed inlet or flash zone may have problems when
processing crudes high in naphthenic acid.
Vacuum column
-
Superheated steam
Flash zone is often one of the worst naphthenic acid
problem areas.
With highly naphthenic crudes, all areas of the column
operating above 232C (450F) may be susceptible to
naphthenic acid corrosion.
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Crude Distillation and Desalting
•
2-21
Sidestream strippers
-
-
In sweet crude plants, conditions are usually not
threatening for sulfur corrosion even though diesel and
atmospheric gas oil feeds are 288C (550F) and 343C
(650F).
In plants running sour crude, hot strippers are susceptible
to sulfur corrosion.
2.8.2 Exchangers and Piping
Crude operating conditions that may cause corrosion in exchangers
and piping include the following:
•
Presence of water (fresh, brackish, or seawater) in water-cooled
exchangers.
•
Hot hydrocarbon service with increasing sulfur content in
crudes.
•
Initial condensation areas of the atmospheric column and preflash column overhead systems cause the most severe corrosion
problems since these are the areas where HCl vapor dissolves in
the condensing water to form hydrochloric acid (H2S is also
present in these areas).
•
Chloride ions may be present in the overhead receiver water.
•
Heat exchangers closest to the point of initial condensation or
chloride salt deposition are subject to chloride salt fouling and
corrosion.
•
Carbon steel exchanger shells may be strongly attacked by
chloride salts, particularly around inlet nozzles.
•
CO2 and H2S may be present in the condensing vapors in the
overhead vacuum condensers.
2.8.3 Fired Heaters
Crude operating conditions that may cause corrosion in fired heaters
include the following:
•
Elevated temperatures exist on the process side as well as in the
fire-box.
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Crude Distillation and Desalting
•
Atmospheric heater receives flashed crude at about 260C
(500F) and sends it to the atmospheric column at about 365C
(690F).
•
Vacuum heater has an inlet temperature of 360C (680F) and an
outlet temperature of 382C (720F).
•
Sulfur compounds and naphthenic acids may be present.
•
High fire-box temperatures (816C [1500F]) create material
problems from oxidation, sulfidation, and premature failure.
•
Units burning fuel oil high in sodium and vanadium may be subject to fuel ash corrosion.
•
Vacuum heater outlet piping and transfer line may be severely
attacked by naphthenic acid.
2.9 Other Corrosion Combating
Measures
In addition to proper material selection, several corrosion control
methods can be used to reduce the severity of acid attack in the
crude unit overhead circuit. These include:
•
Blending
•
Desalting
•
Caustic addition
•
Overhead pH control
•
Use of corrosion inhibitors
•
Water washing.
2.9.1 Blending
Blending problem crudes with non-problem crudes is perhaps the
most common technique for corrosion control. Sometimes blending
may not significantly reduce the corrosion problems, or the
flexibility between crudes may not exist so that blending is not a
viable option for corrosion control. In both instances, other
corrosion control measures are required.
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2.9.2 Desalting
As discussed previously, desalting is a pretreatment process
designed to reduce the amount of salt in crude oil. A common target
level for desalting is to reduce the salt to less than 3 ppm. Removal
of the salt reduces the amount of HCl produced from hydrolysis in
the preheat and flash zone of the crude tower. In addition to salt
removal, the desalting process also removes entrained solids, such
as sand, salt, rust, and paraffin wax crystals, which may be present
in the crude. Removal of these contaminants helps decrease
plugging and fouling in heaters and preheat exchangers.
2.9.3 Caustic Addition
The addition of a small amount of dilute caustic (sodium hydroxide
[NaOH]) to the desalted crude is often an effective way to reduce
the amount of HCl released in the preheaters. The caustic converts
the HCl to thermally stable sodium chloride (NaCl), reducing the
amount of free HCl produced. While the results of caustic addition
can be quite beneficial, there is a risk of crude preheat train fouling;
accelerated atmospheric, vacuum, and visbreaker or coker coking;
caustic stress corrosion cracking; and catalyst contamination
problems in downstream units if it is not properly controlled. A
typical limit for avoiding coking problems in furnaces is to inject no
more than necessary based on downstream chloride (20 ppm to 30
ppm in the atmospheric column overhead water) or sodium limits
(20 wppm to 50 wppm in the vacuum tower bottoms).
Fresh caustic is preferred over spent caustic for two major reasons:
1. Spent caustic tends to have variable amounts of free or available
NaOH to neutralize HCl and, as a result, proper control is very
difficult.
2. Spent caustic, depending on its source, can be a significant promoter of preheat exchanger fouling.
To minimize the negative effects of caustic injection and maximize
its efficiency, thorough mixing is necessary. To achieve good
mixing, the caustic is often added to suction of the crude booster
pumps after desalting. Some refineries will mix by injecting the
dilute caustic into a slipstream of desalted crude oil prior to its
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Crude Distillation and Desalting
injection into the main process stream. Injection of caustic upstream
of the desalters is not recommended because high desalter water pH
can result in the formation of emulsions and can drive ammonia into
the crude. Also, the caustic will be unavailable to react where the
salt hydrolysis takes place since it will typically be removed in the
desalter brine. For units without a desalter, to minimize potential
for caustic cracking, if possible, caustic should be added to the
preheat train at or about desalter outlet temperature.
2.9.4 Overhead pH Control
An overhead pH control program is designed to produce an
essentially non-corrosive environment by neutralizing the acidic
components in the overhead liquid. pH control is accomplished by
injecting ammonia, an organic neutralizing amine, or a combination
of the two. The desired pH control range depends on the
concentrations of the various components of the corrosive
environment. Usually, this range is 5.5 to 6.5. However, it is
important to recognize that neutralizers may have only a different
effect on the pH at the initial condensation point. At this point, the
pH could be higher or lower, depending on the product selected. A
pH above 8 must be avoided if brass alloys are used in the overhead
system since they are vulnerable to stress corrosion cracking and
accelerated corrosion at high pH.
The preferred injection point for the neutralizer is open to debate. In
single overhead drum systems, some chemical vendors advocate
injecting the neutralizer into the column reflux stream to help
protect the tower internals. Others discourage this practice because
neutralizer-chloride salts, similar to ammonia salts that form in the
tower, may be corrosive especially to copper-bearing alloys and
may be trapped in a section of the tower. Because stability of
neutralizer-chloride salts varies depending on the type of neutralizer
used, the various options and their risks should be discussed with
the chemical vendor prior to implementing a chemical treatment
program.
In two-stage overhead systems, in which part of the naphtha is
condensed in the first stage with the remaining naphtha plus water
condensed in the second stage, the neutralizer or ammonia (or both)
is normally injected upstream of the second-stage condensers.
Generally, neutralizers are not used in the first stage if it operates
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without water condensation due to concerns with forming corrosive
neutralizer-chloride salts, which may also be refluxed to the tower.
Wet first-stage systems, however, may benefit from neutralizer
addition if there is a continuous water draw from the first stage
drum. Neutralizers are sometimes used in vacuum tower overhead
systems as well, using an application point that minimizes or
eliminates the possibility of introducing neutralizer-chloride salts
into the tower.
A variety of neutralizers and blends of neutralizers are available for
pH control. Some neutralizer components in widespread use today
include ammonia (NH3), morpholine, ethylene diamine (EDA),
monoethanolamine (MEA), and methoxypropylamine (MOPA). All
of the neutralizer salts are water-soluble. MOPA and MEA form
liquid neutralizer salts with chlorides at elevated temperatures.
NH3, morpholine, and EDA form solid salts. Liquid salts may be
less prone to fouling, but they may also flow better and result in
more widespread salt corrosion if they are returned to the
atmospheric tower.
2.9.5 Corrosion Inhibitor
Most overhead corrosion control programs include the injection of
proprietary film-forming organic inhibitors, commonly referred to
as filmers. These inhibitors establish a continuously replenished
thin film, which forms a protective barrier between acids in the
system and the metal surface underneath the film. For maximum
results, proper pH control of the system is essential.
Filming-inhibitor injection rates will vary with time and between
refineries. There is a surface adsorption/desorption steady state
established, which varies based on the aggressiveness of corrosion
in the system and the inhibitor concentration. Factors that affect
inhibitor solubility in the liquids, such as pH, and affect the
inhibitor’s ability to adsorb on the surface, such as temperature, will
influence the effective dosage for a given situation. A typical
injection rate is of the order of 3 vppm to 5 vppm for normal
operations. During startups or unit upsets, injection rates may be
temporarily increased, to levels such as 12 vppm, to help establish
or re-establish the protective film. Inhibitors also could have a
cleaning effect in that they may remove some iron sulfide deposits,
particularly at the higher injection rates.
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Crude Distillation and Desalting
Because these inhibitors have high molecular weights, they are nonvolatile and will follow the path of other liquids present following
their injection. Therefore, they must be independently injected into
both stages of a two-stage overhead system. Filming inhibitors
should normally not be injected in concentrated form. Inhibitors are
non-corrosive to equipment at treatment dosage dilutions, but near
100% concentration, they may be corrosive to injection equipment.
Typically, naphtha dilution is provided to help the dispersion at the
injection point.
In the feed to the atmospheric and vacuum columns as well as in the
columns themselves, naphthenic acid corrosion can occur. There has
been some success with the use of corrosion inhibitors purported to
be effective in the 260C to 370C (500F to 700F) temperature
range and for this type of corrosion. These inhibitors may offer
some economic advantage over alloys when the acidic crudes are
charged intermittently, but their effectiveness is hard to determine.
Additionally, most of the inhibitors available contain phosphorus,
which may be considered to be a poison to some hydrotreating
catalysts.
2.9.6 Water Washing
Water washing can be effective in removing products of
neutralization reactions, such as ammonium chloride or amine
chloride, which can be highly corrosive and also cause fouling. It is
common practice to recirculate water from the overhead receiver
back into the column overhead vapor line. Some refineries also use
stripped sour water and/or other water condensates for water
washing. Water containing dissolved oxygen can dramatically
accelerate corrosion and should be avoided. Water washing can be
very effective in controlling corrosion, but must be carefully
engineered to prevent the creation of more corrosion problems and
to avoid significant loss of heat exchange in the overhead naphtha
coolers.
Water washing the vapor line can prove to be beneficial or
disastrous. Too little water can just add to the acid making process,
and too much water can cause grooving of the line. The path of the
grooves can be unpredictable and difficult to locate with normal
ultrasonic testing surveys. A proper spray nozzle is necessary to
prevent impingement corrosion of the pipe downstream of the
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injection point. When the wash water is injected directly upstream
of the condensers, a good distribution system is necessary to ensure
evenly divided flow among the different banks of exchangers. An
intermittent wash is difficult to optimize, may be neglected, and
may actually increase corrosion of otherwise dry and non-corrosive
salts. Therefore, use of water on an intermittent basis should be
considered only when a continuous wash is not possible due to
process constraints or when a continuous wash has been shown to
create erosion problems.
The ideal water injection rate is 5% to 10% of the overhead stream.
Excessive water rates, however, can result in poor water separation
in the overhead drum. Poor separation can result in water being
returned to the tower in the reflux and resultant corrosion both in the
tower and the overhead line. With the proper mechanical design and
chemical balance, the water wash can be an important part of the
overhead corrosion control program.
2.10 Corrosion Monitoring in Crude Units
Several methods are used to evaluate the effectiveness of crude unit
corrosion control programs, including:
•
Water analysis (overhead corrosion control)
•
Hydrocarbon analysis
•
Corrosion rate measurement
•
On-stream, non-destructive examination.
2.10.1 Water Analysis (Overhead Corrosion
Control)
The most important monitoring parameter for good overhead
corrosion control is receiver pH. The system pH can shift from an
acceptable pH to an aggressively corrosive pH in a matter of
minutes, so the overhead receiver pH should be measured as
frequently as possible in the atmospheric column. The preflash
column and vacuum column pH will usually not shift as rapidly.
Continuous pH monitor reliability is poor relative to most other
instruments used in refining, and so most refineries still rely on
manual readings. Although pH measurements can capture a
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Crude Distillation and Desalting
corrosive event and prevent extended damage, even holding the pH
in an acceptable range does not always assure the lowest possible
corrosion rate.
Routine analysis of the overhead receiver water for metals can be of
value in some cases, particularly when used in conjunction with
other methods of measurement. Iron, copper, and zinc are typically
measured, but this depends on the materials used in the overhead
system. If no brass, copper, nickel, or UNS 04400 alloys are used,
for example, there is little value in determining copper, nickel, or
zinc concentrations. Much reliance has been put on the iron content
of the water and, very often, the results are misleading. Since iron
solubility is quite dependent on pH, the iron concentration in the
receiver may not be indicative of the amount of iron going into
solution somewhere upstream where the pH may be lower. The
only source of copper and zinc in a typical system would be brass or
UNS 04400 exchanger bundles.
Overhead receiver water chlorides are a very useful parameter to
measure. Since aqueous corrosion is almost always related to the
quantity of hydrochloric acid or chloride salts, measuring chlorides
can help confirm when a corrosion event began and how long it was
sustained. A regular measurement of chlorides can also be used to
optimize caustic addition or blending of crudes.
Hardness is an additional measurement that can be useful for
corrosion control. The hardness of water condensing in an overhead
system should be zero. If any hardness is detected, it generally will
mean a leak has occurred in a cooling water exchanger. If a
recycled water wash is in use, a cooling water leak means that
oxygenated water is being recycled. Oxygen can accelerate
corrosion. Additionally, the hardness from the water can precipitate
when the water is injected into the overhead, causing the severe
fouling. If hardness is detected, adjustments to the corrosion control
program may be required, and repairs may need to be scheduled.
2.10.2 Hydrocarbon Analysis
For filming inhibitors used in an overhead to control aqueous
corrosion, depending on the inhibitor formulation, it is sometimes
possible to run a residual test on a stream to detect the presence of
the corrosion inhibitor. The environment affects the adsorption/
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2-29
desorption steady state that accompanies the use of inhibitors. A
sufficient amount of inhibitor must be present to continuously
replenish the film. This is often seen as a residual of 3 ppm to 5
ppm.
For naphthenic acid corrosion control measurement, sometimes the
only tool for measuring the aggressiveness of the environment is
metals analysis of the oils. Historical data is used as a check on
current conditions. The absolute value of the metals content will
change when naphthenic crudes are processed.
2.10.3 Corrosion Rate Measurement
Corrosion rate measurements are made with electrical resistance
probes, weight-loss coupons, or linear polarization resistance
probes. Electrical resistance probes are widely used, but with varied
results. These probes only indicate corrosivity of the measured
stream at the point where the probe is located. It is not always
possible to relate the probe readings to a pipe wall or the condensing
surfaces of exchanger tubes. However, they perform well in
evaluating a corrosion control program, which changes the
environment through pH control and inhibitor injection. They also
have the advantage of being read on-stream. Electrical resistance
probes are most commonly used in the tower overhead systems.
They are often used at both the inlet and outlet of overhead
exchangers and may be installed in the bulk sour water draw-off
from the overhead drum.
Weight-loss coupons yield a calculated corrosion rate based on
initial surface area and weight and lend themselves to visual
examination as well. However, they must be removed to provide
information, and they cannot represent heat transfer surfaces.
Weight-loss coupons are commonly used in overhead systems and
can often be replaced on-stream.
Linear polarization resistance probes provide an instantaneous
corrosion rate based on a measurement of the probe element
corrosion current. This type of probe works only in a conductive
medium and is used for on-stream measurements. It performs well
in bulk water systems like cooling water streams. Applications in
the overhead receiver water drum are limited but feasible.
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2.10.4 On-Stream, Non-Destructive
Examination
Ultrasonic testing (UT) and radiography (RT), types of nondestructive examination, are not normally used for extensive
corrosion monitoring due to their cost. They are most often used
on-stream on an exception basis when there is a confirmed or
suspected problem, which is being watched closely. UT and RT are
used to check piping and vessels for changes in wall thickness.
UT readings can be taken easily and quickly on most surfaces,
which can be reached by the inspector. Scanning UT methods are
particularly well suited to areas where localized corrosion can occur,
such as high turbulence areas in the hot or overhead systems or in
areas of the overhead system vulnerable to underdeposit corrosion
or impingement.
RT is also an important on-stream inspection tool. In addition to
measuring wall thickness, it can be used to indicate the presence of
pitting and, under some circumstances, show thickness of deposits
on pipe walls.
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2.11 Optional Team Exercise
Working in teams:
1. Use the material presented up to this point in Chapter 2 and identify on the crude unit distillation diagram provided below locations within a crude unit that may be subject to corrosion.
Specify the type(s) of corrosion likely for each location.
Crude Distillation Unit
Neutralizer
Filming Amine Inhibitor
Crude Preheat
Gases
Cooling
H2O
Light
Liquids
Sour Water
Water Recirculation
Dist.
Naphtha
Reflux Naphtha
Naphtha
Kerosene
Desalted
Crude
30-45 psig
Heater
Atmospheric Distillation
Primary Flash
Caustic
(Optional)
600-7000F
700 F +
Max. Vacuum
Steam
Vacuum Distillation
Diesel Oil
500-600F
30-45 psig
Light
Medium
Heavy
Gas Oils
Superheated
Steam
Residue
to Coker
or
Asphalt
Heavy Components
2. Using the material presented in this chapter and in the slide
presentation, select materials to use for corrosion protection
of crude distillation unit equipment and piping.
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3. Complete the following form as you make your material
selections.
Crude Unit
Equipment/Piping
Material
Corrosion Control in the Refining Industry Course Manual
Reason(s) for
Selection
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Fluid Catalytic Cracking Units
3-1
Chapter 3:Fluid Catalytic Cracking
Units
Objectives
Upon completing this chapter, you will be able to do the following:
•
Define fluid catalytic cracking
•
Explain the part played by zeolites in the catalytic cracking
process
•
State the temperature at which the catalytic cracking process
takes place
•
Label the components of a reactor system
•
Explain the role of the FCC reactor vessel
•
Explain the function of the regenerator
•
Explain the function of the flue gas system
•
Explain the function of the fractionator
•
Identify the typical materials of construction employed in
catalytic cracking units
•
Identify the principal corrosion risks in FCC reactors
•
Explain the difference between hot-wall and cold-wall reactors
•
Identify the typical corrosion prevention factors used to reduce
corrosion of reactor internals
•
Establish the priority and schedule for first-time inspection for
wet H2S damage to equipment
•
Identify the principal damage mechanisms involving regenerators
•
Identify the typical corrosion prevention factors used to resist
corrosion in regenerators
•
Identify the principal damage mechanisms involving flue gas
systems
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Fluid Catalytic Cracking Units
•
Identify the typical corrosion prevention factors used to resist
corrosion in flue gas systems
•
Using an appropriate reference, identify the location, inspection
techniques, and control measures for types of corrosion and
erosion in FCC units.
3.1 Introduction
Fluid catalytic cracking (FCC) involves cracking heavy oils or
residuum feedstocks by using elevated temperature, relatively low
pressure, and a catalyst.
Earlier in the history of the refining industry, the gasoline yield per
barrel of crude was lower. The crude could only be separated into its
component molecules. This generally resulted in more fuel oil than
was economically desirable and, as the demand for gasoline
increased in relation to that for fuel oil, the problem grew more
acute.
This created a glut of fuel oil, increasing the price of gasoline and
depressing the price of fuel oil. To deal with this problem, the
industry developed several methods for breaking up the larger crude
molecules into components that would increase gasoline yield and
the price of fuel oil. The most popular of these techniques was
catalytic cracking.
Feedstocks for an FCC unit usually include straight run heavy gas
oils and coker gas oils but, with more advanced catalysts, can
include atmospheric residuum and vacuum tower bottoms. Tops
from the flasher can also serve as feed. The boiling point for
feedstock is generally in the 650F to 1100F (343C to 593C)
range. The process requires additional heat, which is primarily
supplied by the catalyst that has been heated in the regenerator.
Temperature in the cracker vessel is usually 900F (480C).
Operating conditions, catalyst, and hardware are designed to
maximize production of high-octane gasoline, but isobutane and
light olefins suitable for downstream production of premium
gasoline blending components, such as methyl tertiary butyl ether
(MTBE) and alkylate, are also obtained.
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If the process worked perfectly, all the product would be in the
gasoline range, but the typical cracking process is not that efficient.
During the cracking reaction, several things happen. As the larger
molecules are broken up, there is not enough free hydrogen to meet
the demand, or saturate, all the carbon compounds. A small amount
of the carbon becomes coke, which is basically pure carbon atoms
stuck together. Also, as the large molecules break up, a broad range
of smaller molecules is created. These consist of methane and
lighter compounds. Due to the insufficiency of hydrogen, many of
these molecules are olefins.
When the larger molecules crack, those that consist of small rings
(mostly aromatics and naphthenic compounds and some olefins) are
produced. The products of catalytic cracking, therefore, include the
full range of hydrocarbons from methane down to residuum and
coke.
The cracking reaction is accomplished by subjecting a vaporous
feed stream of heavy, long-chain hydrocarbon molecules to
fluidized catalyst at 900F to 1000F (480C to 540C) for a few
seconds. The FCC process relies on synthetic zeolitic catalysts,
which consist of a mixture of fragile crystalline aluminosilicate
materials (zeolites) dispersed in an amorphous mixture of active
alumina, silica, clays, etc.
The zeolites provide the primary cracking function. When viewed
under a microscope, the catalyst particles display a large number of
pores, called a matrix, which greatly increases the surface area of
the catalyst. The reaction aided by the catalyst occurs only at the
catalyst surface, so the matrix is critical to the efficiency of the
process. The matrix also offers size, strength, hardness, and density.
It facilitates heat transfer during operation, and promotes some
degree of added cracking of the heaviest feed components.
The name, Fluid Catalytic Cracking Unit, is derived from the
manner in which the catalyst is handled. It moves through the plant
in a fluidized state. Modern cat crackers use catalyst in the form of a
fine powder (older ones used small pellets). The catalyst, when
placed in a beaker and tilted, flows like a fluid.
The central item in an FCC is the reactor. See Figure 3.1.
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Fluid Catalytic Cracking Units
Figure 3.1 Catalytic Cracker Reaction Chamber
In fluidization, gas in the form of air, steam, or vaporized
hydrocarbon is heated and travels through the powdered catalyst at a
velocity sufficient to suspend it. This results in an aerated solid-gas
mixture that acts as a boiling, bubbling fluid that is continuously
circulated between the regenerator and reactor. This mixture enters
the reactor through a line called a riser, which leads into the bottom
of the reaction chamber. A considerable amount of the cracking
process happens in the riser, so the actual time spent in the reactor is
only a few seconds. The reactor is principally used as a catalyst/
hydrocarbon separator.
Catalyst transport is controlled primarily by differential gas pressure
between the regenerator and reactor, differential catalyst-gas
mixture densities, and slide valves that act as control valves.
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3.2 Hardware
FCC units comprise four principal component systems:
•
Riser/reactor
•
Regenerator
•
Flue gas system
•
Main fractionator.
3.2.1 Riser/Reactor
The riser/reactor portion of the cat cracker is where the cracking
reaction, which typically lasts for 2 to 5 seconds, takes place.
Preheated (500F to 800F [260C to 425C]) gas oil feed enters the
bottom of the vertical riser through a single pipe inlet or multiple
feed nozzles. In the riser, close contact with hot (1250F to 1350F
[675C to 730C]) regenerated catalyst causes the feed to vaporize
rapidly and rise. Cracking begins as soon as the vaporized
hydrocarbon is adsorbed onto the catalyst and enters the pores to
contact active cracking sites. Cracking continues as the mixture of
hydrocarbon charge vapors moves up the riser. A lift gas, typically
steam, can be used to help the vapors move upwards.
During cracking, carbon is deposited on the catalyst in the form of
coke, deactivating the catalyst. By the time the vaporized charge
reaches the reactor, the cracking process is virtually complete and
the catalyst is spent.
Contemporary reactors do little more than separate cracked
hydrocarbon vapors from the catalyst since nearly all cracking takes
place in the riser. However, heat provided by the hot catalyst and
continued contact between the catalyst and hydrocarbon gas keeps
the cracking reaction going. Cyclones (centrifugal separators) are
used to prevent over-cracking by separating the spent catalyst from
the hydrocarbon vapors. Cracked hydrocarbon vapors exit the top of
the cyclones and are transported from the reactor to the main
fractionator through the reaction mix line.
Before leaving the reactor, spent catalyst passes through a stripper
section in the reactor where any remaining adsorbed hydrocarbon is
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Fluid Catalytic Cracking Units
separated from the catalyst by using a combination of stripping
steam and baffles/shed trays.
3.2.2 Regenerator
The regenerator restores catalyst activity by burning catalyst coke
deposits and provides the heat required by the endothermic cracking
reaction. Regeneration temperatures are typically 1200F to 1400F
(650C to 760C). See Figure 3.2.
Figure 3.2 Catalyst Regenerator
The regeneration process begins when spent catalyst from the
reactor enters the regenerator through the spent catalyst standpipe.
Air is used as lift gas to propel the spent catalyst up the standpipe
into the regenerator. Once in the regenerator, the hot catalyst is
contacted by oxygen and combustion begins.
Coke is consumed in the combustion process, producing
regenerated catalyst, flue gas, which is mostly CO and CO2, but can
contain SOx, NOx, and heat. The heat is retained by the catalyst to
sustain cracking in the reactor.
Most of the combustion occurs in the bottom of the regenerator
above the air distributor where the catalyst concentration is greatest
(dense phase). Little combustion occurs in the upper part of the
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regenerator or dilute phase, which is primarily flue gas and
entrained catalyst.
Cyclone separators are used to disengage catalyst carried upward by
rising flue gas. The flue gas escapes from the top of the cyclones
into the flue gas system. The recovered catalyst is directed down to
the dense phase of the regenerator.
Catalyst transfer piping used to continuously carry fluidized catalyst
from the reactor to the regenerator and back again can be arranged
as U-shaped lines or vertical standpipes and risers. Standpipes and
risers are the most common arrangement today. The driving forces
to move regenerated catalyst from the regenerator vessel to the
reactor are gravity and the higher pressure in the regenerator. As
discussed previously, lift gas propels the spent catalyst into the
regenerator.
3.2.2.1 Flue Gas System
The flue gas system is responsible for heat recovery and purifies
regenerator waste gas for discharge to the atmosphere by cooling the
gas, removing catalyst fines, and removing pollutants. Waste flue
gas leaves the regenerator at 1250F to 1400F (675C to 760C).
In most units, flue gas passes downward through a steam generator
or vertical shell and tube heat exchanger called a flue gas cooler to
produce additional steam for the refinery. Electrostatic precipitators
or wet gas scrubbers are used to remove fine catalyst particles called
fines, which are too small to be removed by the regenerator’s
cyclone separators. Stack scrubbers remove fines and pollutants
(NOx, SOx, etc.). Flue gases are then either discharged into the
atmosphere or burned in a carbon monoxide (CO) boiler for further
heat recovery.
3.2.2.2 Fractionator
The main fractionator cools the cracked reactor effluent gas and
separates the light and heavy cycle oils from the lighter fractions
(cracked gasoline, olefins, etc.). See Figure 3.3.
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Figure 3.3 Fractionation
The cat-cracked gasoline makes a good motor blending component;
light cycle oil makes a good blending stock for No.2 domestic
heating oil or diesel fuel, and heavy cycle oil is fed to a coker,
hydrocracker, or used as a residual fuel component.
In some FCC processes, cycle oil is recycled into the feedstock
(hence its name). In these processes, cycle oil is processed to
extinction and is not further processed using other units.
There is considerable latitude in the cut point between the gasoline
and light gas oil components. This allows adjustment in the output
mix as the seasons change. During the winter heating oil season,
refineries switch to a maximum distillate mode. During the summer,
the operation changes to a maximum gasoline mode, by shifting the
cut point the other way.
The light ends produced by the fractionation process, unlike those
from the traditional distillation process, contain unsaturated
compounds like olefins. The C4 and the lighter stream contain not
only methane, ethane, propane, and butanes, but also hydrogen,
ethylene, propylene, and butylenes. For this reason, this stream must
be separated in a cracked gas plant. The unsaturated products are
important feedstocks for the process of alkylation, a process that
converts these olefins to components suitable for blending gasoline.
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The components described above are shown in Figure 3.4.
Figure 3.4 Generic Fluid Catalytic Cracking Unit Process Flow Diagram
The process contains two circular flows: one involves the catalyst
and the other, cycle oil.
The purpose of this entire process is to convert heavy gas oil into
lighter components. The process works well; typical yields are
illustrated in Table 3.1 on page 10.
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Table 3.1: Typical FCC Yields
Feedstock:
Heavy Gas Oil
Flasher Tops
Cycle Oila*
Total
% Volume
40.0
60.0
10.0
100.0
Yield:
Coke
C4 and Lighter
8.0
35.0
Cat-Cracked Gasoline
Cat-Cracked Light Gas Oil
Cat-Cracked Heavy Gas Oil
Cycle Oil*
Total
55.0
12.0
8.0
10.0
118.0
a.
*The recycle stream is not included in feeds or yeild total.
The main fractionator does not require a reboiler since heat can be
supplied solely from the hot gas leaving the reactor. Stripping steam
is often used at the fractionator inlet to drive the hydrocarbon
molecules farther apart, making them easier to fractionate. The
steam also helps carry the lighter gases up the tower. Bottoms
temperatures in most main fractionators are in the range of 650F to
750F (340C to 400C).
The overhead stream (200F to 250F [95C to 120C]) from the
fractionator is piped to a gas recovery section for further
fractionation, caustic treating, and H2S removal. The additional
fractionation produces light and heavy gasolines as well as propane,
butane, and light gas.
3.3 Corrosion Control in FCC Units
3.3.1 Materials of Construction
Common materials of construction in FCC units include:
•
Carbon steel
•
1-1/4 Cr low-alloy steel
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•
5 Cr low-alloy steel
•
9 Cr low-alloy steel
•
12 Cr stainless steel
•
300 series stainless steel
•
400 series stainless steel
•
Alloy 625 nickel-based alloy
•
Refractory linings.
See Figure 3.5.
Figure 3.5 Generic Fluid Catalytic Cracking Unit, Materials of Construction
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3.3.2 Damage Mechanisms and Suitable
Materials
3.3.2.1 Reactors
Several damage mechanisms need to be taken into consideration
when designing, modifying, or inspecting an FCC unit reactor:
•
Materials exposed to full reactor temperatures must resist hightemperature sulfidation and carburization
•
Both metals and refractory linings must resist catalyst erosion
•
Metals must not be susceptible to metallurgical changes leading
to embrittlement, deformation, internal fissuring, or early failure
•
Design should account for thermal expansion to avoid mechanical distress/cracking.
3.3.2.2 Reactor Shell
Reactors are divided into hot-wall and cold-wall design. Hot-wall
reactors, which may be refractory lined for erosion resistance, are
typically constructed of low-alloy steel, such as 1-1/4 Cr-1/2 Mo.
This alloy is selected over carbon steel for its improved hightemperature strength and freedom from graphitization.
Cold-wall reactors are constructed with carbon steel shells that are
internally insulated. To combine good erosion resistance and
insulating properties, two cold-wall refractory systems—dual-layer
linings or single-layer, intermediate-density castables—can be
employed in the reactor.
In the early years of the refining industry, dual-layer linings were
used exclusively. They consisted of a 4 in. (100 mm) insulating
layer of soft-density refractory against the shell, which was
protected from erosion by a 1 in. (25 mm) thick hard layer of highdensity refractory packed into 12 Cr or into type 304 stainless steel
hexmesh. Metal studs attached the hexmesh to the shell.
Due to the expense associated with and the difficulty in maintaining
dual-layer linings, a single, thick layer of medium-weight,
intermediate-density castable, supported by type 304 stainless steel
vee anchors is used more frequently today. This type of lining does
not offer as much insulation as the light-weight insulating refractory
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nor as much erosion resistance as the hard, high-density refractory,
but is generally effective.
3.3.2.3 Reactor Internals
Reactor internals, such as cyclones, grids, and stripping section
baffles, are typically constructed of carbon steel, but can be
protected by using 12 Cr stainless steel in some areas. Carbon steel
cyclones and dip legs typically suffer from erosion damage and
must be internally protected by an erosion-resistant lining of hard,
high-density refractory supported by 12 Cr stainless steel hexmesh.
Type 304 stainless steel hexmesh cannot be used here because of the
difference in thermal expansion relative to the carbon steel
substrate. The carbon steel reactor cyclones can also suffer a slow
metal loss due to carburization because they have hot process gas on
all sides and cannot be kept cool with insulating refractory.
Although cyclones fabricated from 12 Cr stainless steel have
improved resistance to carburization, the 12 Cr stainless steel may
embrittle at reactor operating temperatures.
3.3.2.4 Regenerators
Damage mechanisms to consider when designing, modifying, or
inspecting an FCC regenerator include:
•
High-temperature oxidation
•
High-temperature carburization
•
Catalyst erosion
•
Embrittlement
•
Internal fissuring
•
Early failure
•
Mechanical distress/cracking.
3.3.2.5 Regenerator Shells
Regenerator shells are commonly constructed of carbon steel, with
internal refractory linings used to keep the shell cool enough to
avoid loss of strength, prevent graphitization, and protect against
erosion, oxidation, and carburization.
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A dual-layer refractory lining or a single-layer, medium-weight
refractory lining may be used. The 12 Cr (type 410) or 18 Cr-8 Ni
(type 304) stainless steel hexmesh is supported by carbon steel
studs. As regeneration temperatures rose over the years, type 410
stainless steel studs replaced the carbon steel studs.
Today, intermediate-density refractory materials are popular for use
on regenerator shells. These materials don’t insulate as well as the
light insulating refractories nor do they provide as good an erosion
barrier, but they do offer a substantial cost savings and ease of
application. A single-layer, intermediate refractory applied by
gunning and supported by type 304 stainless steel vee studs is the
typical system now used on regenerator shells.
3.3.2.6 Regenerator Internals
In the regenerator internals today, type 304H stainless steel is used
for cyclones and cyclone support structures. Cyclones are internally
protected by a 1-in. (25-mm) thick, erosion-resistant refractory
lining supported by type 304 stainless steel hexmesh. Recently, “Sbar” anchors are being used in place of hexmesh, especially for
repairs. The anchors bend more easily than hexmesh when fitting on
curved surfaces. The top two feet of cyclone dip legs may also be
lined with refractory.
The predominant air distribution system used to introduce air into
the regenerator used to be perforated grids. Today, multi-nozzle air
distributors and air rings are common. Since grid temperatures are
lower than those in the catalyst bed above the grid, lesser alloys can
be used for the grid than for some of the other regenerator internals.
Plants commonly use grids of 1 Cr-1/2 Mo to 5 Cr-1/2 Mo low-alloy
steel. Grid seals, which accommodate thermal expansion differences
between the grid and the shell and maintain a pressure drop across
the grid, are typically 13 Cr (type 405) stainless steel. Type 304H
stainless steel is used for air ring or multi-nozzle air distributors.
Expansion bellows, used when the spent and regenerated catalyst
standpipes pass through the grid, are typically series 300 stainless
steel or nickel-based alloy 625 (UNSN06625), which has a more
elevated temperature strength. Alloy 625 can embrittle at
regenerator operating temperatures.
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Much of the regenerator internals, such as the outside and inside of
the spent catalyst standpipe and air distribution rings (if used),
subject to erosion are lined. An intermediate-density or phosphatebonded castable with metal fiber for reinforcement is normally used.
These linings are generally 1 in. to 2 in. (25 mm to 50 mm) thick.
3.3.2.7 Catalyst Transfer Piping System
Catalyst transfer piping is usually made of carbon or low-alloy (5
Cr-½ Mo, 9 Cr-1 Mo) steel with an internal refractory lining. The
refractory commonly used today is a single-layer, intermediatedensity refractory, supported by vee studs and reinforced with
stainless steel (type 304) needles.
Early regenerated cat-slide valves were constructed of cast or
wrought type 304 stainless steel bodies and erosion-resistant
refractory linings on parts exposed to flow. Steam was often
introduced as a purge to keep catalyst from collecting in the valve
body. If the valve body were not externally insulated to keep it hot,
water condensation would form at the valve end farthest from flow.
The combination of water and sulfide oxides from the process gas
established an aqueous acidic condition that often led to polythionic
acid stress corrosion cracking of wrought series 300 stainless steel
valve bodies. Cast stainless steel slide valves were susceptible to
sigma phase embrittlement. All problems associated with stainless
steel slide valves can be avoided by using internally insulated and
erosion-resistant refractory-lined carbon steel or low-alloy steel
slide valves.
3.3.3 Reaction Mix Line, Main Fractionator,
and Bottoms Piping
Materials of construction for the reaction mix line include internally
insulated carbon steel or uninsulated 1 Cr-1/2 Mo, 1-1/4 Cr-1/2 Mo,
5 Cr-1/2 Mo, and 300 series stainless steel. Material selection for the
reaction mix line is based on the need for strength and resistance to
high-temperature graphitization. Localized attack by hightemperature H2S is also possible at cool spots where heat is driven
away by external supports. However, the potential for H2S attack in
the reaction mix line does not necessarily justify the expense
associated with upgrading to a more sulfidation-resistant alloy.
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Fatigue cracking has occurred in reaction mix lines, especially at
miters, but can be solved through design. Fatigue cracking can result
from the stress caused by differential thermal growth between the
reactor overhead and the fractionator inlet nozzle.
Fractionator shells are typically carbon steel, clad with 12 Cr
stainless steel (type 405, type 410, type 410S) in areas susceptible to
sulfidation corrosion above 550F (285C). Trays are typically 12
Cr stainless steel (type 405, type 410, type 410S) in hotter areas and
12 Cr or carbon steel further up the column. The inlet nozzle can run
hot enough (900F to 1000F [480C to 540C]) to be susceptible to
high-temperature graphitization.
Hot (650F to 700F [340C to 370C]) oil fractionator bottoms
systems need to resist erosion from catalyst slurry as well as
corrosion from high-temperature H2S. Process fluids entering the
main fractionator contain catalyst fines, which often cause local
erosion in the columns bottom system. Erosion in the lower part of
the main fractionator is normally not a serious problem, but higher
velocity areas in downstream bottoms piping and equipment, such
as pumps, can be significant.
Piping and valves are typically 5 Cr-1/2 Mo or 9 Cr-1 Mo for
sulfidation resistance. Downstream heat exchanger shell/channel
claddings and tubes are often 12 Cr or 300 series stainless steel.
Hardfacing alloys or vapor diffusion coatings are often used to resist
erosion in pressure let-down valves and bottom pumps. The pump
case is either 5 Cr-1/2 Mo, 9 Cr-1 Mo, or 12 Cr stainless steel. Highchrome, erosion-resistant irons are also used for bottoms pumps.
3.3.3.1 Flue Gas Systems
Corrosion concerns in flue gas systems include:
•
Erosion from catalyst fines
•
Oxidation resistance
•
Carburization resistance
•
The need for high-temperature strength.
In flue gas ducts, erosion is more noticeable at elbows than in
straight runs and is severe in and just downstream of restriction
orifices and the slide valve. Piping materials are typically
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refractory-lined carbon steel or, when a power recovery turbine is
used, inlet piping is typically uninsulated 300 stainless steel to avoid
refractory particles entering the turbine.
Flue gas coolers (vertical shell and tube heat exchangers with boiler
feed water shell side) have refractory-lined carbon steel in the inlet
to protect against erosion and overheating. Steam generation heat
exchanger tubes are carbon steel because boiler feed water is used to
cool them, keeping tube metal temperatures low.
3.4 Inspection and Control
Considerations
In FCC units, high temperatures, corrosive liquids and gases, and
erosive solids can result in serious metal loss due to several
corrosion/metallurgical damage mechanisms. See Table 3.2 on
page 18.
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Table 3.2: FCC Unit Reactor Regenerator and Main Fractionator
Damage Mechanisms
Component
Feed Riser
Reactor Internals
Reactor Cyclones
Reaction Mix Line (overhead piping)
Catalyst Transfer Lines
Slide Valves
Regenerator Shell
Expected Damage Mechanism
Catalyst Erosion
Refractory Damage
High-Temperature Sulfidation
High-Temperature Carburization
Creep
Creep Embrittlement
Catalyst Erosion
Refractory Damage
High-Temperature Sulfidation
High-Temperature Carburization
High-Temperature Graphitization
885F Embrittlement
Catalyst Erosion
Refractory Damage
High-Temperature Sulfidation
High-Temperature Carburization
Creep
High-Temperature Graphitization
Catalyst Erosion
High-Temperature Sulfidation
Thermal Fatigue
Catalyst Erosion
Refractory Damage
High-Temperature Graphitization
Cracking from Thermal Stresses
Catalyst Erosion
Refractory Damage
Sigma Phase Embrittlement
Polythionic Acid Stress
Corrosion Cracking
Catalyst Erosion
Refractory Damage
Creep
High-Temperature Oxidation
(Complete Combustion)
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Regenerator Internals
Regenerator Cyclones
Flue Gas Lines and Coolers
Fractionator and Side Cut Piping,
Exchangers
Fractionator Bottoms Piping,
Valves, Exchangers
Catalyst Erosion
Refractory Damage
Sigma Phase Embrittlement
Polythionic Acid Stress
Corrosion Cracking
High-Temperature Oxidation
(Complete Corrosion)
High-Temperature Carburization
(Partial Combustion)
High-Temperature Graphitization
Catalyst Erosion
Refractory Damage
Creep
Sigma Phase Embrittlement
Polythionic Acid Stress Corrosion
Cracking
High-Temperature Carburization
(Partial Combustion)
High-Temperature Oxidation
(Complete Combustion)
Catalyst Erosion
Refractory Damage
Sigma Phase Embrittlement
Polythionic Acid Stress Corrosion
Cracking
High-Temperature Oxidation
(Complete Combustion)
High-Temperature Carburization
(Partial Combustion)
High-Temperature Sulfidation
High-Temperature Graphitization
885F Embrittlement
Catalyst Erosion
High-Temperature Sulfidation
3.4.1 High-Temperature Oxidation
High-temperature oxidation occurs in regenerator internals and the
flue gas system. Visual inspection (a hammer test to remove oxide
scales) can reveal damage and ultrasonic testing (UT) can be used to
determine remaining wall thickness. See Figure 3.6.
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Figure 3.6 Generic Fluid Catalytic Creacking Unit, Inspection Summary Diagram
For control, a resistant alloy containing sufficient chromium
(resistance improves from 5 Cr, 9 Cr to stainless steel) is used.
Internal insulation on the metal surfaces with refractory is employed
to keep them cool. See Table 3.3 on page 21.
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Table 3.3: Inspection and Control Measures for FCCU Reactor,
Regenerator, and Main Fractionator Damage Mechanisms
Damage
Mechanism
High-Temperature Oxidation
High-Temperature Sulfidation
High-Temperature Carburization
Control
Measure
Regenerator internals Visual (use hamUse a resistant alloy conand flue gas system
mer test to remove
taining sufficient chro(e.g. where metal tem- oxide scales and
mium (resistance
peratures exceed
reveal damage). UT improves from 5 Cr, 9 Cr,
1000F/540C)
to determine
to SS). Insulate the metal
remaining wall
surfaces internally with
thickness
refractory to keep them
cool.
Preheater furnace
Attack is quite eas- Use a base metal or cladtubes, feed piping,
ily found by UT or ding/weld overlay with
reactor internals, reac- RT because rates
sufficient chromium
tion mix line, sections are generally pre(resistance improves
of main fractionator
dictable and attack
from 5 Cr, 9 Cr, to SS) to
above 550F (285C), is quite uniform.
resist attack. Insulate the
fractionator bottoms
Pay particular atten- metal surfaces internally
piping and pump,
tion to hot areas of
with refractory to keep
fractionator side cut
the fractionator just them cool.
piping and exchangbeyond the 12 Cr
ers which experience a cladding.
metal temperature
>550F (285C).
Reactor internals
UT to identify wall
(with incomplete com- thinning.
bustion, CO can form
in the regenerator).
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Location
Inspection
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Fluid Catalytic Cracking Units
Polythionic
Acid Stress
Corrosion
Cracking
Regenerator internals,
slide valves, refractory anchors, catalyst
withdrawal lines, flue
gas lines, expansion
bellows constructed of
3xx Series stainless
steel.
Cracking occurs
infrequently. Not
normally part of the
routine inspection
program. If
detected visually,
inspect other weld/
base metal locations
using PT.
Catalyst Erosion
Reactor and regenerator shell and internals
(especially cyclone
separators); catalyst
transfer lines; thermowells; slide valves;
flue gas lines and
coolers; and fractionator bottoms pumps,
heat exchangers,
valves, and piping.
Feed Nozzle
Erosion
Riser pipe just
upstream of the regenerated catalyst entry
point and feed spray
nozzles.
Visual for majority
of equipment and
internals, UT and
RT thickness measurement for piping,
elbows, valves,
reducers, pump discharges, etc. Focus
first on high velocity areas > 50 ft/s
(15 m/s). Damage
can be highly localized.
Visual or RT.
Corrosion Control in the Refining Industry Course Manual
Take precautions during
shutdowns to prevent
polythionic acid formation. Prevent water from
condensing on 3xx Series
stainless steel that
exceeds 700 F (370 C)
in service. Avoid water
washing for dust
removal, use packed and
insulated expansion
joints, change to internally insulated carbon
steel (or purge with
nitrogen rather than
steam). Use low carbon
or stabilized varieties of
3xx Series stainless steel.
Design to minimize turbulence of catalyst and
catalyst carryover. Use
erosion resistant refractory lining and hardfacing. Use SS ferrules in
inlet flue gas coolers of
fractionator bottoms
exchangers.
Design to minimize turbulence on the riser wall.
Use erosion-resistant
materials to extend life of
feed spray nozzles.
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Refractory
Damage
3-23
Reactor and regenerator system, internals,
and associated piping
(e.g., thermal cycling
cracks; loss of
anchors; spalling from
poor installation insufficient dry out, coking.
Visual during shutdowns or survey
cold wall equipment onstream thermography (e.g.,
pyrometers or infrared analyzers) to
identify failure of
insulating refractory.
Proper refractory selection, application, dry-out,
curing, reinforcement
(e.g., metal fibers), and
anchoring.
High-Tempera- CS reactor cyclones;
ture Graphitiza- fractionator inlet noztion
zle and adjacent shell;
and any location
where the thermal
insulation is damaged (e.g., reactor and
regenerator internals,
catalyst transfer lines)
so that metal temperatures exceed 800F
(425C) (if carbon
steel) and 850F
(455C) (if carbonmolybdenum steel).
Sigma Phase
Welded 3xx Series
Embrittlement
stainless steel regenerator internals or flue
gas system components and cast 3xx
Series stainless steel
slide valves exposed
to temperatures
between 1100F to
1700F (590C to
925C).
RT, shear wave UT,
and field metallography of weldments.
Use chrome-molybdenum steels rather than
carbon steels or carbonmolybdenum steels for
pressure containing components. Insulate the
metal surface with refractory to lower metal temperatures.
PT for cracks or
field metallography
to identify presence
and distribution of
sigma phase.
Control ferrite content of
weld metal to 3% to 10%.
Exercise caution when
performing maintenance
work at ambient temperature. Minimize shock
loading to potentially
embrittled material. For
the case of slide valves,
move to internally-insulated carbon or low alloy
steel.
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855F (475C)
Embrittlement
Creep Embrittlement
High-Temperature Creep
Thermal
Fatigue
Fluid Catalytic Cracking Units
4xx Series stainless
steels exposed to
700F to 1000F
(370C to 540C). 3xx
Series stainless steel
welds and cast components can also experience embrittlement.
Highly stressed
welded components
constructed of C-1/2
Mo, 1Cr, and 1-1/4 Cr
steels at >850F/
422C (e.g. nozzle
welds).
PT for cracks or
field metallography
to identify presence
and distribution of
embrittlement
phase.
Do not use 4xx Series
stainless steels in pressure-containing, hightemperature environments.
PT or shear wave
UT of highly
stressed weldments
for cracks in the
base metal heat
affected zone.
Hot-wall reactor vessels, carbon steel reactor cyclones and
hangers, and stainless
steel regenerator
cyclones and hangers. Regenerators or
cold-wall reactors can
experience creep if the
insulating refractory
fails.
Reaction mix line,
especially at miters.
Visual and PT to
look for cracking
and distortion in
structural and pressure-containing
components.
Creep embrittlement has
not yet become an issue
for 1-1/4 Cr components
in FCCs. Specifying
higher purity 1-1/4 Cr
steel or 2-1/4 Cr steel is
means to prevent embrittlement.
Ensure actual service
metal temperatures do not
exceed design metal temperatures (e.g., prevent
overheating). In areas
exhibiting metal deformation, use stress-analysis techniques to ensure
thermal expansion
stresses are accounted for
in design.
Best to eliminate risk of
cracking through design.
Eliminate mitered joints
where stresses concentrate.
Visual or PT for
cracks.
1. CS = carbon steel; 1 Cr = 1 Cr-1/2 Mo alloy steel; 2-1/4 Cr =
2-1/4 Cr-1 Mo alloy steel; 5 Cr = 5 Cr-1/2 Mo alloy steel; SS
= stainless steel, either 12% Cr (4xx Series) or 18% Cr – 8%
Ni (3xx Series).
2. RT = Radiographic Testing, UT = Ultrasonic Testing, and PT
= Dye Penetrant Testing.
Although low-chrome steels such as 1-1/4 Cr-1/2 Mo are not much
better in oxidation resistance than carbon steel, 5 Cr-1/2 Mo
oxidizes at reduced rates and 12 Cr provides even better resistance.
However, for parts operating at full regenerator temperatures,
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austenitic (300 series) stainless steels, such as type 304 and type
304H with 18% Cr, are required. Type 304 stainless steel is typically
used in regenerators for cyclones and hexmesh/S-bars supporting
refractory.
3.4.2 High-Temperature Sulfidation (H2S
Attack)
Hydrogen sulfide (H2S) is formed in the FCC preheater and reactor
by thermal decomposition of organic sulfur compounds in the plant
feed. It is corrosive to iron and steel at high temperature (above
550F [285C]) in concentrations greater than 1 ppm.
High-temperature sulfidation (H2S attack) occurs in:
•
Preheater
•
Feed piping downstream of the preheater
•
Reactor
•
Reaction mix line
•
Sections of main fractionator above 550F (285C)
•
Fractionator bottoms piping and pumps
•
Fractionator side cut piping
•
Exchangers, which experience a metal temperature 550F
(285C).
High-temperature sulfidation corrosion does not occur rapidly
enough in FCC units to create the probability of catastrophic failure.
UT or Radiographic Testing (RT) easily detect attack since rates are
generally predictable and attack is quite uniform. It must be noted
that areas of the fractionator just beyond the 12 Cr cladding are quite
susceptible to this type of attack.
For control, a base metal or cladding/weld overlay with sufficient
chromium is employed to resist attack. 5 Cr-1/2 Mo, which is the
least alloyed of the iron-based alloys, offers better resistance than
carbon steel. Examples of alloys used to resist high-temperature
sulfidation, include:
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•
5 Cr-1/2 Mo steel, which is used for hot side cut/bottoms piping
and heat exchanger tubing downstream of the main fractionator.
•
1-1/4 Cr-1/2 Mo steel, which has provided acceptable sulfidation
rates when used for carbon steel reactor cyclones, reactor effluent lines, and hot-wall reactor shells. Although 1-1/4 Cr-1/2 Mo
steel is generally not considered to have reliable sulfidation
resistance, it has proved acceptable in this service.
•
12 Cr stainless steel, which some refineries have used to upgrade
reactor cyclones since these steels are not corroded by H2S under
any conditions found in a FCC unit. Note the caution on 885F
embrittlement in Table 3.3.
•
Type 304, type 321, and type 347 stainless steels, which are also
used for cyclones because they are also totally resistant to hightemperature H2S attack.
Sulfidation resistance can also be achieved by insulating the internal
metal surfaces with refractory to keep them cool. For example, coldwall reactors are internally insulated carbon steel.
3.4.3 High-Temperature Carburization
At high temperatures above 1000F (540C), metals can absorb
carbon from the surrounding atmosphere to form metal carbides, a
process called carburization. Carburization in FCC units begins
with the deposition of carbon (coke) on the metal surface. The
carbon then reacts with the metal to form metal carbides. As the
metal carbide penetrates the metal and forms a layer, it experiences
a high compressive stress since it occupies a greater volume than the
unaffected metal. The metal carbide either bulges away from the
unaffected metal or flakes off, reducing metal thickness in the
process. (See Chapter 1 for more information).
High-temperature carburization occurs in reactor and regenerator
internals. With higher operating temperatures and incomplete
combustion, CO can form in the regenerator flue gas system. The
excess CO has carburized even 300 series stainless steel.
UT can be used to identify wall thinning. As a general rule,
chromium seems to retard carburization in oxidizing or sulfidizing
environments, but not in reducing environments. For unknown
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reasons, 1-1/4 Cr-1/2 Mo reactor shells have not been found to
carburize significantly.
3.4.4 Polythionic Acid Stress Corrosion
Cracking
Partially oxidized sulfur acids, which are commonly called
polythionic acids, are not found in the FCC unit during operation
except in regenerator and flue gas areas, which can cool below the
liquid acid dew point. They develop during shutdowns from the
oxidation of iron sulfide in the presence of moisture and oxygen.
(See Chapter 1 for more information).
Polythionic acid stress corrosion cracking occurs in:
•
Regenerator internals (refractory anchors with hexmesh,
cyclones)
•
Slide valves
•
Series 300 catalyst withdrawal nozzles
•
Flue gas lines
•
Expansion bellows.
This type of cracking occurs infrequently and, therefore, inspection
is not routine. If detected visually, other similar weld/base metal
locations are inspected using dye penetrant testing (PT.).
Three basic means of preventing polythionic acid stress corrosion
cracking are:
•
Using alloys that resist sensitization (low-carbon or stabilized
varieties of 300 series stainless steel)
•
Isolating sensitized stainless steels from sulfur-derived acids
•
Preventing polythionic acid formation.
Control precautions during shutdowns to prevent polythionic acid
formation include:
•
Preventing water from condensing on 300 series stainless steel
that exceeds 700F (370C) in service
•
Avoiding water washing for dust removal
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•
Using packed and insulated expansion joints
•
Changing to internally insulated carbon steel slide valves rather
than stainless steel (or purging with nitrogen rather than steam).
3.4.5 Catalyst Erosion
Erosion, which is the largest problem in the hot (dry) sections of
FCC units, is the loss of material due to the impact and cutting
action of solid particles in a high-velocity stream. The rate of
catalyst erosion is influenced by the properties of the material
surface being eroded.
Catalyst erosion can be found in:
•
Reactor and regenerator shell and internals (especially cyclone
separators)
•
Catalyst transfer lines
•
Thermowells
•
Slide valves
•
Flue gas lines and coolers
•
Fractionator bottoms pumps, heat exchangers, valves, and
piping.
Visual inspection is used to detect catalyst erosion for the majority
of affected equipment and internals; UT and RT thickness
measurements are taken for piping, tees, elbows, valves, reducers,
pump discharges, etc. Inspection should focus first on high-velocity
areas, as damage can be localized.
Designs that help control this problem include:
•
Minimizing turbulence of catalyst and catalyst carryover
•
Using erosion-resistant refractory linings and hardfacing
•
Using stainless steel ferrules in the inlet of flue gas coolers and
fractionator bottoms exchangers.
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3.4.6 Feed Nozzle Erosion
Feed nozzle erosion occurs in the riser pipe upstream of the
regenerated catalyst entry point and feed spray nozzles. Detection
and control measures include:
•
Visual or RT inspection methods to detect feed nozzle erosion
•
Designing to minimize turbulence on the riser wall
•
Using erosion-resistant materials to extend the life of feed spray
nozzles.
3.4.7 Refractory Damage
Refractory damage occurs in the reactor and regenerator system,
internals, and associated piping and includes:
•
Thermal cycling cracks
•
Loss of anchors
•
Spalling from poor installation
•
Insufficient dry-out
•
Coking.
Inspection and control measures for refractory damage include:
•
Visual inspection during shutdowns
•
Surveying cold-wall equipment onstream, using thermography
(pyrometers or infrared analyzers) to identify insulating refractory failure
•
Proper refractory selection, application, dry-out/curing reinforcement (metal fibers), and anchoring.
3.4.8 High-Temperature Graphitization
In carbon and carbon-molybdenum steels, the carbon exists largely
as iron carbide. When steel is exposed to very high temperatures, the
iron carbide decomposes to form ferrite (iron) and graphite
(carbon), which is a process called graphitization. Graphite is a
substance with very little strength or ductility and, therefore, its
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formation triggers corresponding losses of these properties in the
metal.
When metal temperatures exceed 800F (425C) for carbon steel
and 850F (455C) for carbon-molybdenum steel, high-temperature
graphitization can occur in the:
•
Carbon steel reactor cyclone
•
Fractionator inlet nozzle and adjacent shell
•
Any location where the thermal insulation is damaged, such as
reactor and regenerator internals or catalyst transfer lines.
RT, shear wave UT, and field metallography of weldments can be
used to identify high-temperature graphitization.
Control measures include the use of chrome-molybdenum steels (11/4 Cr-1/2 Mo) rather than carbon steel or the use of carbonmolybdenum steels for pressure-containing components (up to a
maximum temperature of 850F [455C]). Carbon steels can be
used for pressure-containing components up to temperatures of
800F (425C). In addition, insulation of the metal surface with
refractory can be employed to lower metal temperatures.
3.4.9 Sigma Phase Embrittlement
The brittleness caused by sigma phase formation tends to disappear
when the metal is heated above approximately 500F (250C) and to
reappear upon cooling below this temperature. As a result,
embrittlement is not likely to cause an onstream failure, but may
occur when performing maintenance work. (See Chapter 1,
Corrosion and Other Failures, for more information on sigma phase
embrittlement)
Sigma phase embrittlement occurs in the ferrite phase of welded 300
series stainless steel regenerator internals or flue gas system
components and cast 300 series stainless steel slide valves exposed
to temperatures between 1100F to 1700F (590C to 925C).
Inspection and control measures include:
•
PT inspection for cracks
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•
Field metallography to identify the presence and distribution for
the sigma phase, although detection of sigma phase would be
very difficult.
•
Limiting ferrite content of weld metal to 3% to 10%
•
Avoiding shock loads when the metal is cold
•
Using type 304 stainless steel in the regenerator system rather
than other austenitic stainless steel grades, such as type 321 and
type 347
•
Using internally insulated carbon or low-alloy steel for slide
valves.
3.4.10 885F (475C) Embrittlement
885F (475C) embrittlement occurs in 400 series stainless steels
exposed to 700F to 1000F (370C to 540C) and 300 series
stainless steel welds and cast components. Inspection and control
measures include:
•
PT inspection for cracks
•
Not using 400 series stainless steels in pressure-containing,
high-temperature environments.
3.4.11 Creep Embrittlement
Creep embrittlement is found in the weld heat-affected zone of
highly stressed welded components constructed of C-1/2 Mo, 1 Cr1/2 Mo, and 1-1/4 Cr-1/2 Mo steels, i.e., nozzle welds. During hightemperature operation above 850F (455C), the heat-affected zone
will tend to crack at the weld fusion line.
Inspection and control measures include:
•
Inspection with PT or shear wave UT of highly stressed weldments for cracks in the base metal heat-affected zone
•
Specification of higher purity 1-1/4 Cr steel or 2-1/4 Cr-1/2 Mo
steel.
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3.4.12 High-Temperature Creep
At low temperatures, if a metal is stressed below the yield point, it
will spring back elastically to its original size when the stress is
removed. When stressed above its yield point, the metal will
permanently deform. If the stress remains constant, no further
deformation occurs. However, at high temperatures, applying a
stress below the yield point causes the metal to stretch permanently
as the load is applied. This phenomenon is called creep and will
eventually cause the metal to fail.
High-temperature creep can occur in hot-wall reactor vessels;
carbon steel reactor cyclones and hangers; and regenerators, piping,
or cold-wall reactors if the insulating refractory fails. Inspection and
control measures include:
•
Visual inspection and PT to look for cracking and distortion in
structural and pressure-containing components
•
Ensuring that actual service metal temperatures do not exceed
design metal temperatures
•
In areas which exhibit metal deformation, using stress-analysis
techniques to ensure thermal expansion stresses are accounted
for in design
•
Using alloy upgrades.
3.4.13 Thermal Fatigue
Thermal fatigue may be found in the reaction mix line, especially at
miters. The differential growth between the reactor overhead and the
fractionator inlet nozzle is the source of the fatigue stress. A high
stress is placed on the mix line each time the reactor temperature is
cycled.
Inspection and control measures include:
•
Visual inspection or PT to look for cracks
•
Eliminating the risk of cracking through proper design
•
Eliminating mitered joints where stresses concentrate.
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3.5 Optional Team Exercise
Use the following form as you and your team members prepare a
corrosion inspection plan. Your instructor will provide directions
for the team exercise during the class session.
Corrosion Inspection Plan
Date/ Freq.
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Equipment
Component
Damage
Expected
Results
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Chapter 4:Cracked Light Ends
Recovery Units
Objectives
Upon completing this chapter, you will be able to do the following:
•
Describe the cracked light ends recovery (CLER) process
•
Identify typical materials of construction used in CLER units
and the reasons for their use
•
Identify corrosive agents present in CLER units and describe the
types of damage that may result
•
Discuss corrosion control measures that are effective in preventing corrosion in CLER units.
4.1 CLER Process Description
CLER units process the material from the overhead system of the
main fractionator of a Fluid Catalytic Cracking Unit (FCCU) or
similar process unit that yields cracked components. The purposes
are to recover propane and heavier components and to separate light
boiling fractions. A flow diagram of a CLER unit is provided in
Figure 4.1.
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Figure 4.1 Cracked Light Ends Recovery Unit
Gases from the FCCU main fractionator are condensed to allow
collection and separation of light cracked naphtha and off gases.
The off gases from the main fractionator reflux drum are then
compressed and cooled in one or more stages. The hydrocarbon
liquid condensate streams go to a stripper (de-ethanizer) tower while
the remaining non-compressed gases are typically sent to an
absorber tower. In many cases, these are combined as one tower
structure. The de-ethanizer removes fuel gas components (C1s and
C2s). The absorber uses chilled condensate from the main
fractionator reflux drum (wild gasoline) as lean oil to absorb
remaining C3s and heavier components, allowing the fuel gas
components to go overhead.
The resulting rich oil is combined with the stripped condensate from
the de-ethanizer and sent to a debutanizer and depropanizer (or
naphtha splitter). These towers separate the streams into propane,
butane, light cracked naphtha, and heavy cracked naphtha.
4.2 Materials of Construction
All components in CLER units, including piping, are usually made
from carbon steel (CS). CS can be used because essentially the
hydrocarbon streams are below 300ºF (150ºC), and CS forms a
protective sulfide film when exposed to sour waters containing
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ammonia bisulfide. Fractionator internals are thinner and corrode
from both sides, so they are typically constructed of type 405 or type
410S stainless steels. Tubes for overhead condensers and
compressor aftercoolers can be admiralty brass, alloy 400 (UNS
NO4400), duplex stainless steel, or titanium depending on cooling
water corrosion considerations.
In recent years, special hydrogen induced cracking (HIC) resistant
steels have been used to mitigate hydrogen-induced damage
concerns. Stainless steel clad equipment has also been used to
remove the risk of hydrogen-induced damage altogether.
The following material points out where problems occur in major
equipment and systems and examines the materials commonly used
to alleviate those problems.
4.2.1 Columns
Most columns, such as the absorber, de-ethanizer, debutanizer,
depropanizer, and naphtha splitter, are constructed of carbon steel.
As mentioned previously, the most common problem in CLER units
is HIC and hydrogen blistering due to exposure to active ammonia
bisulfide and cyanide solutions. Therefore, many columns are
constructed of special carbon steels (HIC-resistant) that improve the
resistance to hydrogen damage. In some cases due to the size and
complexity of the columns, stainless steel cladding (typically 304L)
is used to remove this concern.
Tray internals of the columns can be carbon steel particularly in the
drier back end towers. 400 series stainless steel is often used in the
wetter, first columns to provide alkaline sour water corrosion
resistance for these thinner components.
4.2.2 Exchangers
The majority of exchangers in these units are coolers, condensers, or
tower reboilers. CS is the material of choice for the process side,
which is usually the shell side, of the coolers, but the cooling water
medium may dictate other needs. Given the alkaline, ammonia
(NH3) rich sour water, the use of copper-based alloys, such as
admiralty brass, aluminum brass, and copper-nickels, may be
accompanied by the risk of corrosion or possibly ammonia stress
corrosion cracking. Therefore, other water-resistant plus sour water-
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resistant alloys, such as titanium (grades 2 and 12) and duplex
stainless steels are often used. Exchangers in CLER units are subject
to the same HIC and blistering risks as are columns. Therefore,
HIC-resistant steels or stainless steel clad shells may be used.
Reboilers are also usually constructed of carbon steel unless dictated
by the corrosivity of the heating medium, which may involve steam
and hot fractionator streams. The primary process side problem with
reboilers is the collection of upstream corrosion products in the
bottom of the exchanger that causes underdeposit corrosion. Some
refineries have removed the bottom rows to alleviate this problem.
4.3 Corrosion Problems
Corrosion problems in CLER units result from low-temperature
corrosion mechanisms.
4.3.1 Corrosion
Corrosion is caused by a combination of aqueous hydrogen sulfide
(H2S), ammonia (NH3), and hydrogen cyanide (HCN), leading to
sour water corrosion. The rate of corrosion can vary extensively,
depending on the concentration of the above compounds and on
specific process parameters. The amount of H2S, NH3, and HCN
formed in the FCCU is usually a function of the amount of sulfur
and nitrogen in the FCCU feed. In addition, the actual operation of
the FCCU reactor system, i.e., reactor temperature and extent of
catalyst burn, may affect the amount of H2S, NH3, and HCN formed
for a given feed.
In the absence of HCN, aqueous sulfide solutions with pH values
above 8 do not generally corrode carbon steel because a protective
iron sulfide (FeS) film will form on the surface. This FeS is soft and
can be disrupted by flow effects, such as turbulence or very high
velocities. HCN, if present in significant quantities, destroys this
protective FeS film and converts it into soluble ferrocyanide
[Fe(CN)6 –4] complexes. As a result, the now unprotected steel can
corrode very rapidly. The corrosion rate depends primarily on the
bisulfide ion (HS-) concentration and, to a lesser extent, on the
cyanide (CN) concentration. For practical purposes, the HS- and
CN concentrations found in CLER units, usually do not cause
severe corrosion of carbon steel. However, units with excess
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amounts of chlorides in the fractionator, i.e., enough to cause
ammonia chloride salting, may have acidic shock condensation
occur in the first condensation zone of the fractionator overhead.
If excess NH3 is generated and the pH rises above 8.0 to 8.5,
copper-based alloys are subject to accelerated corrosion and/or
ammonia stress corrosion cracking. Corrosion is also caused by the
formation of soluble cyanide complexes that react with the copperbased materials. Monel (70% Ni, 30% Cu) has been successfully
used in these services, generally since the temperatures are low
enough to sustain protective sulfide scales.
Chromium (Cr) containing materials generate more stable complex
sulfide films and, hence, improve the resistance to sour water
corrosion.
For this reason, various forms of stainless steels have been used
subject to fabrication and cooling water considerations. At very high
ammonia bisulfide levels, complexing by cyanides can be a
problem, even for the stable Cr-based sulfide scale, and corrosion of
stainless steel can occur. Generally, the levels of ammonia bisulfide
found in CLER units are not high enough to cause this type of
corrosion.
Titanium generates a very stable oxide that is virtually immune to
sulfides. As a result, it has been used particularly in conjunction
with seawater cooling. However, titanium can become embrittled
due to hydrogen generated as part of ongoing system corrosion
reactions. The hydrogen reacts directly with titanium to form
hydrides that substantially reduce the toughness of the material.
This damage is accelerated by temperature and galvanic coupling
with other metals.
(Note: See Chapter 1 for more informationon wet H2S cracking,
hydrogen blistering, sulfide stress cracking, hydrogen induced
cracking and stress-oriented hydrogen induced cracking.)
4.3.2 Hydrogen Induced Damage
As part of the corrosion process, atomic hydrogen (H) forms and
evolves from cathodic areas of the metal as molecular hydrogen
(H2). When corrosion rates are high enough, desorption of
molecular hydrogen from the surface becomes rate controlling.
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Atomic hydrogen builds up on the surface, especially in sulfide
solutions, and will enter the steel matrix where it can cause several
forms of damage.
Atomic hydrogen diffuses into the steel and forms molecular
hydrogen at voids, such as manganese sulfide inclusions or
laminations. Because of their larger size, hydrogen molecules
cannot diffuse out of the steel, and accumulating hydrogen gas
builds up pressure, deforming the surrounding metal. Blistering and
cracking are the result. During the manufacture of steel plate,
contaminants and slag residues segregate as inclusions and
laminations in planes primarily concentrated at ¼, ½, and ¾ of the
plate thickness. Since corrosion and, therefore, hydrogen diffusion
proceeds from the inside of the vessel, blisters will be generally
found on the inside vessel wall. If inclusions and laminations at the
inner plane are patchy, atomic hydrogen could diffuse through the
plate thickness to the center and outer planes of segregation. In the
latter case, blisters would be expected to show up on the outside
vessel wall.
If there are several layers of inclusions and they are close together,
smaller internal blisters can form at different planes. Cracking can
progress from the blister edges, joining with other blisters causing
stepwise cracking through the thickness of the steel.
If high stresses, such as those due to weld residual stresses or stress
concentration at other crack tips, are coincident with the stepwise
crack formation, cracking can become more oriented in the throughthickness direction of the plate, and stress oriented hydrogen
induced cracking (SOHIC) results.
Finally, in high-strength steels, which are typically found in bolting,
high-hardenability welds, or heat-affected zones, the atomic
hydrogen saturates the matrix, embrittling it and making it
susceptible to stress cracking.
The amount of hydrogen in ammonia bisulfide solutions that
penetrates into steel is typically a function of pH. Acidic solutions
will generate higher hydrogen permeation, while a neutral pH will
show a decrease. pH above 8 will show a steady increase in
permeation. At typical CLER pH, ammonia bisulfide would
generate nominal hydrogen damage potential.
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HCN, as it disrupts the FeS scale, increases corrosion and as a result
greatly increases the hydrogen available for damage. The effect is
so great that apparent corrosion rates may still be quite low, but
sufficient hydrogen enters the steel to cause extensive damage.
Hydrogen damage of carbon steel has caused damage to coolers,
separator drums, absorber/stripper towers, and overhead condenser
shells. Usually, the attack occurs in interstage and high-pressure
separator drums and in absorber/stripper towers. Vapor/liquid
interface areas often show most of the damage, probably because
NH3, H2S, and HCN concentrate in thin water films or in water
droplets that collect at these areas.
4.3.2.1 Inspection Techniques for Hydrogen-Induced
Damage
As a result of the extensive experience with hydrogen-induced
damage in CLER units, inspections are generally carried out to
monitor for this problem. Common techniques include wet
fluorescent magnetic particle inspections for surface cracking on
equipment interiors and ultrasonics to detect both subsurface
blistering and cracking. Acoustic emission may be used to screen
vessels for cracking activity during pressurization cycles.
4.3.2.2 Prevention and Repair Techniques
Blistering can be vented to prevent crack growth. Cracks can be
ground out, and weld repairs are done as needed. The extent of
repairs is assessed by appropriate engineering support and code
requirements. Heat treatment prior to welding can be performed to
bake out absorbed atomic hydrogen to prevent further cracking
during repairs. Post weld heat treatment (PWHT) to temper
hardenable welds and heat-affected zones and to reduce residual
stresses is also often used.
In severe cases of hydrogen-induced damage, equipment
replacement may be required. Special carbon steels with lower
sulfur levels, shape controlling of the remaining sulfur, normalized
heat treatment, and hardenability limits are often specified for this
service. In some cases, the use of stainless steel cladding is
specified to eliminate the problem totally.
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4.3.3 Ammonia Stress Corrosion Cracking
Admiralty brass tubes in overhead condensers are exposed to high
levels of NH3. As a result, it is common for tubes to fail from
ammonia stress corrosion cracking. Admiralty metal tubes can also
corrode from severe localized corrosion attack. Admiralty metal
tubes in compressor aftercoolers have lasted only several months on
some units. For improved service life, replacement with duplex
stainless steel or titanium tubes is often necessary.
4.3.4 Carbonate Stress Corrosion Cracking
he FCCU generates CO2, with small amounts being carried through
with the light ends into the CLER unit. The CO2 is soluble in the
condensing waters and can form carbonates in the solution. A
carbonate-rich solution, when exposed to the residual stresses
usually associated with welds, can cause intergranular stress
corrosion cracking of the heat-affected zone. This phenomenon has
been reported in vessels and piping in CLER units. Since PWHT
considerably reduces welding residual stresses, it is effective in
reducing this problem.
4.3.5 Fouling/Corrosion of Reboiler Circuits
It is commonly reported that reboiler exchangers accumulate
upstream corrosion products. This leads to underdeposit corrosion,
particularly on the tube surfaces. The tube surface tends to
evaporate the water present and to concentrate and precipitate ionic
species causing the underdeposit corrosion.
4.4 Corrosion Control Measures
Certain process modifications have been found to effectively reduce
or prevent corrosion and hydrogen-induced damage in CLER units.
These include:
•
Water washing of certain process streams to dissolve and dilute
corrosives, i.e., H2S, NH3, and HCN
•
Polysulfide injection into wash water to lower HCN content
•
Corrosion inhibitor injection.
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While these measures are useful in reducing blistering, it is
doubtful, however, that any or all of these measures will
significantly reduce or prevent stress corrosion cracking at hard
welds and heat-affected zones. High-strength bolting, used typically
in floating head covers of exchangers, will also be susceptible to
stress corrosion cracking.
4.4.1 Water Washing
Extensive field experience has shown that continuous water
washing of sour gas/vapor streams can be an important method of
controlling corrosion and hydrogen entry into steel. Water washing
can be done by contacting the gas/vapor streams with water in a
scrubbing tower or injecting the water directly into process piping.
A scrubbing vessel is the most efficient method of contacting the
gas. However, many plants use a combination of large water
volume rates and a distribution nozzle to wash the gas in-line.
Water washing primarily dilutes the concentration of NH3 and HCN
in process water. The greatest benefits of water washing are seen in
the high-pressure section where the partial pressures and, hence, the
concentrations of dissolved NH3 and HCN are highest. Water is
generally injected into the main fractionator overhead, upstream of
intermediate compression stage coolers and/or upstream of the final
compression stage coolers.
It is important that the process water, including wash water, not be
returned from the high-pressure section to the main fractionator
reflux drum at the FCCU prior to disposal. This would cause H2S,
NH3, and HCN to flash off as the pressure is reduced at the reflux
drum. As a result, their concentrations would build up in the
compression loop.
It is also important that carryover of corrosive water into
downstream equipment be minimized. This means that sufficient
cooling capacity must be provided for compressor aftercoolers to
maintain separator drum temperatures as low as possible. On some
units, additional drum capacity may be required, along with waterdraw facilities for certain fractionator towers.
Wash water should be injected through a type 304 or type 316
stainless steel distributor or quill that is located at the center of the
piping. There should be at least 15 ft. of piping downstream of the
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injection point to ensure proper mixing ahead of coolers and
condensers. The same applies to piping bends, elbows, and tees
that, otherwise, would experience impingement attack. Where
parallel heat exchanger banks are being washed, care must be taken
to ensure even water distribution. This can be accomplished with
either balanced piping or individually controlled injections into each
bank of exchangers.
Only high-quality water, with low solids content should be used for
water washing. Water quality should be balanced against availability
and cost. Typical water sources are one or more of the following,
listed in order of increasing cost:
•
Sour water condensate (pH 6 to 8.5)
•
Stripped sour water
•
Boiler feeder water
•
Demineralized water, steam condensate, or steam.
If water washing is to be combined with polysulfide injection,
alkaline sour water is preferred. The wash water minimum pH
should then be 8.
It is common to cascade waters from the main fractionator through
the intercoolers and the aftercoolers. Since the water is pumped to
higher pressures, it can absorb more of the corrodents while at the
same time minimizing the net quantity of sour water produced.
The amount of wash water depends on the gas/vapor flow rate, the
amount of water vapor present, and the amount and types of
corrosives present. Ideally, the amount of wash water should be the
minimum needed to meet one or more of the following typical
criteria, listed in order of decreasing importance:
•
HCN content of all water draws less than 20 ppm to 25 ppm by
weight.
•
pH value of all water draws between 8.0 and 8.5.
•
20 gpm (10,000 lb/hr) per MSCF/SD of vapors from the top of
the main fractionator of the FCCU.
Depending on the system, several different types of wash water may
have to be injected to meet these criteria. For example, a slightly
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acidic sour water stream may be required to depress pH values.
Polysulfide may have to be added to the wash water to decrease
HCN levels.
4.4.2 Polysulfide Injection
Continuous injection of polysulfide solution into the wash water
lowers the HCN content of sour water condensate by forming
harmless thiocyanates (SCN). Polysulfide also reacts with sulfide
corrosion products to produce a more protective film on steel
surfaces. Polysulfide injection should be considered if water
washing by itself does not decrease the HCN content below the
recommended 20 ppm to 25 ppm by weight criterion.
While several types of polysulfide solutions are available, most
refiners prefer to use commercial 55% by weight ammonium
polysulfide ([NH4]2Sx) solution containing 35% by weight
polysulfide sulfur. Sodium polysulfide solution is not recommended
because it increases the pH of sour water condensate and reacts
more slowly with HCN in comparison to ammonium polysulfide. It
is also considerably more expensive than ammonium polysulfide
solution.
Polysulfide solution should be stored and handled in CS or stainless
steel equipment. To avoid sulfur deposition, the solution should be
diluted by a factor of 10 with a slipstream of alkaline sour water.
The diluted polysulfide solution is then injected into the various
wash water streams, using a simple T-connection.
As a rule, the injection rate is designed so that the amount of
polysulfide sulfur added is 50 percent more than the stoichiometric
amount required for conversion of HCN to SCN. Actual injection
rates are adjusted to ensure some excess polysulfide that is usually
monitored by observing the color of the condensed waters. A straw
yellow color indicates excess polysulfide. The actual amounts of
free HCN and SCN can also be measured. The target amount for
free HCN is 20 wppm to 25 wppm and, with polysulfide injection,
free cyanide levels much lower than this are routinely achieved.
However, most analytical techniques tend to be either inaccurate or
imprecise.
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4.4.3 Corrosion Inhibitors
Commercial film-forming amines have reduced hydrogen blistering
of steel provided the inhibitor concentration was sufficiently high.
In practice, this meant at least 30 ppm by volume versus the normal
10 ppm.
For this reason, inhibitor injection is relatively uneconomical and
recommended only for problem areas and short-term protection
until other measures, such as water washing or polysulfide injection,
can be implemented. Also, because inhibitors provide significant
protection only in liquid, wetted areas, they do not protect against
blistering in vapor-phase areas of equipment.
4.5 Corrosion Monitoring
Hydrogen-activity probes and periodic chemical tests are
recommended for monitoring the effectiveness of corrosion control
measures.
4.5.1 Hydrogen-Activity Probes
Hydrogen-activity probes use a pressure gauge to measure the
amount of hydrogen that has diffused through a tubular CS
specimen. Recommended key locations for hydrogen-activity
probes include:
•
Different elevations of the absorber/stripper tower
•
The vapor/liquid interface area of the high-pressure separator
drum.
To avoid faulty readings due to leaks, hydrogen-activity probes must
be pressure-tested with hydrogen or helium gas, and a residual
pressure of hydrogen gas should be maintained in the probes at all
times. Changes in pressure due to hydrogen activity are of greater
interest than the actual pressure itself. To facilitate reading and
adjusting, pressure gauges and bleed-off valves of elevated probes
may be kept at ground level and connected to the probes by stainless
steel capillary tubing. Depending on the sensitivity of the hydrogenactivity probes, increases in reading of less than 1 psig/day to 2 psig/
day indicate satisfactory control.
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Figure 4.2 Hydrogen Activity Probe
Other hydrogen activity measurement techniques are also available.
For example, a sealed patch may be mounted on the exterior surface
of a piece of equipment suspected of hydrogen buildup. The
hydrogen passes through the steel wall and is collected within the
sealed patch. Measurement of the hydrogen buildup can involve
various methods, such as vacuum loss or reactions with solid state
or wet chemistry detectors.
4.5.2 Chemical Tests
Chemical tests for cyanide and thiocyanate content of wastewater
streams should be carried out to determine if any changes occurred
due to feed and operations changes. They can also be used to
monitor water wash and polysulfide injection systems. The actual
chemical analysis may be a difficult technique, and care must be
taken to account for air exposure to obtain consistent results. Air
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will convert ever-present sulfides to polysulfides and then gradually
convert CN to thiocyanates. As a result, particularly in polysulfideinjected systems, a simple sampling test often used is color
monitoring during each shift or on a daily basis. However, periodic
laboratory tests are still needed because other components can affect
the color of the water.
Water pH sampled from high-pressure condensates is also
commonly used to monitor water wash rates. Care must also be
taken since H2S and NH3 will flash off when depressurized and
affect the pH readings. Samples should be collected in pressurized
sample containers to obtain meaningful results.
4.5.3 Corrosion Probes
Corrosion probes can be used to monitor ongoing corrosion in
CLER units. The probes are especially useful for monitoring highpH corrosion when copper-based alloys are used in condenser/
cooler bundles. They are less useful in monitoring carbon steel
corrosion and blistering because metal loss rates are typically very
low.
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Chapter 5:Hydrofluoric Acid
Alkylation Units
Objectives
Upon completing this chapter, you will be able to do the following:
•
Identify the purpose and main aspects of hydrofluoric acid alkylation units
•
Identify the major sections in hydrofluoric acid alkylation units
and describe the processes taking place
•
Identify the main process parameters that affect corrosion in
hydrofluoric acid alkylation units
•
Identify and discuss materials of construction for equipment
•
Identify locations susceptible to degradation
•
Identify and discuss degradation mechanisms that may occur
•
Identify and discuss degradation mitigation methods
•
Identify corrosion control measures
•
Identify corrosion monitoring methods
•
Identify areas for inspection and discuss possible techniques to
use.
5.1 Introduction
This chapter reviews fundamental corrosion issues concerning the
hydrofluoric (HF) acid alkylation (HF alky) unit of a petroleum
refinery. The chapter summarizes a description of the process, major
equipment found in the HF Alky, types of corrosion and where they
occur, corrosion control and monitoring used, and a list of related
references for further reading.
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5.2 HF Alky Process Description
The purpose of the alkylation process is to produce a high-octane
gasoline-blending component. In the alkylation process, isobutane
(iC4) is reacted with various olefin feeds (butene, butylene,
propene, propylene etc.) to form an isoparaffin called alkylate. HF
acid is the catalyst used to drive the combination reaction of
isobutane to the olefin to form alkylate. An overall processing
schematic can be found in Figure 5.1.
Figure 5.1 HF Alkylation Process Flow 2
Feeds to the unit must be treated to remove H2S and moisture.
Amine treating, caustic treating, and Merox treating are forms of
sulfur removal. Drying is very important in that incoming water will
dilute the HF acid causing excessive corrosion. Excessive amounts
of water will also result in high acid losses as a constant boiling
mixture (CBM) composed of approximately 35% HF and 65%
water will form. The CBM is then extracted from the unit leading to
losses.
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The isobutane, olefin feeds and HF is combined in a reaction section
of the unit. There are two major licensors of HF alkylation
technology and as such the unit processing is slightly different for
each but the basic flow is similar.
Mixing of the three components occurs in a reactor vessel. As the
reaction is exothermic the reactor consists of a water cooled heat
exchanger bundle to keep temperatures below 100oF. The
hydrocarbon and acid emulsion are sent to a settler drum to separate
out the bulk of the acid which is then recirculated (either pumped or
by gravity feed) back to the reactor. The hydrocarbons with some
dissolved acids are sent to downstream fractionation.
Downstream fractionation is usually done in conventional towers in
which various hydrocarbon components are extracted. Generally a
first fractionation tower removes unreacted isobutane, non-reactive
propane and butane and dissolved HF. The isobutane is withdrawn
and recirculated back to the reaction section. The overhead
consisting of the non-reacted light ends are condensed and sent for
further fractionation. Free HF acid will also condense and be
collected and recovered in this overhead and returned to the reaction
section. The tower bottoms is alkylate product which is sent to a
trace HF removal section.
The non-reacted overheads are further fractionated in depropanizer
and/or debutanizer towers and final HF stripper towers. Again free
HF may condense in the overheads and is collected and returned to
the reaction section.
All products (alkylate, propane, butane) are finally treated to reduce
the trace fluorides to very low (1-10 wppm) acceptable levels.
Otherwise, combustion of theses streams as fuels will lead to
corrosive vapors. HF removal can occur by either passing the
stream over hot alumina beds and/or the use of solid or aqueous
potassium hydroxide (KOH) treaters.
Eventual water accumulation and acid soluble oils within the unit
will lead to dilution of the HF acid which if allowed to get to too
low a level (approx. 80% ) will lead to accelerated corrosion. Acid
soluble polymer oils form as part of side reactions in the reactor
which also need removal. As a result there is a need to regenerate a
portion of the acid to remove the water and oils. This can be done on
a continuous or batch basis. This usually involves a separate hot
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distillation tower (regenerator or rerun tower) where the higher
water acid is heated to drive off free HF in a tower for recovery back
into the unit. The remaining water forms the CBM mixture (which
has a high boiling point (350oF) which along with polymers are
drawn from the bottom of the tower and neutralized prior to
disposal. One licenser uses the isostripper tower to perform insitu
(in tower) acid regeneration. A slipstream of the acid is injected into
the feed where the polymer fractionates into the alkylate and is
removed. Water cannot be removed with this process but the amount
of external regeneration is reduced.
5.3 Materials of Construction
Components in HF Alky units are usually made from carbon steel
(CS). CS can be used because essentially the hydrocarbon streams
are below 150°F (65°C) where free acid may exist and the HF acid
is at high enough strengths (> 80%) to create protective fluoride
scales. In higher temperature areas such as the regeneration system
Alloy 400 (UNS N04400) is used due to its higher corrosion
resistance in hot HF (in absence of oxygen) and erosion resistance in
high velocity/turbulent areas such as pump internals and valves.
Alloy 400 may also be used along with 70/30 CuNi (UNS C71500)
in reactor and heat exchanger tubing in acid and trace acid services
as these alloys have the improved acid resistance as well as cooling
water resistance.
High quality carbon steel with restricted chemistry has been used for
vessels. In addition, some companies specify clean steels (HIC
Resistant steels) that are tested to NACE TM0284 with some form
of crack length ratio criteria. This is helpful in the prevention of
hydrogen blistering and hydrogen induced cracking (HIC). Post
weld heat treatment (PWHT) can be used to lower residual stresses
and hardness that could contribute to a hydrogen damage
mechanism. Alloy 400 clad equipment has also been used to
remove the risk of hydrogen induced damage altogether.
It is important to point out that the high Si containing slags that form
with shielded metal arc welding (SMAW) and submerged arc
welding (SAW)) welds or as inclusions in carbon steel castings are
readily attacked by HF acid leading to possible through wall
leakage. Hence extra care in weld cleaning, use of inert shielded
welds, extra inspections are usually specified to limit this risk.
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Alloy 400 in cast forms (pump bodies, valves) can have lower
corrosion resistance than its wrought equivalent if the chemistry is
not carefully controlled. High Si contents can improve corrosion
resistance. Both M-35-1 and M30C casting grades of Alloy 400
have been successfully used in plants. It has been reported that the
Cb stabilized cast version (M30C) can suffer selective attack of the
columbium carbides and hence corrode at a higher rate in some
severe circumstances.
The purpose of the following section is to point out where problems
occur in major equipment and systems, and to discuss the materials
commonly used to alleviate those problems.
5.3.1 Columns
Most columns (isostripper, debutanizer, depropanizer, HF stripper)
are constructed of carbon steel. As discussed in the materials and
corrosion problem section, the most common problem is hydrogen
induced cracking and blistering due to exposure to active HF
corrosion. Columns have therefore been recently constructed of
clean steels or some companies have used special carbon steels
(HIC resistant) that improves the resistance to hydrogen damage. In
some cases due to the size and complexity of the columns, Alloy
400 cladding is used to remove this concern. Some fractionation
towers are used to regenerate acid by a slip stream injection of acid
into the hydrocarbon and have had higher corrosion rates to CS in
the upper sections and have required replacements sooner and/or
cladding in Alloy 400. The hotter regeneration tower requires
construction of solid or clad Alloy 400 to resist the higher
temperature, lower acid strength solutions.
Tray internals of the columns can be carbon steel particularly in the
drier section of the towers. Alloy 400 is often used in the HF acid
exposed sections to provide HF corrosion resistance for these
thinner components.
5.3.2 Exchangers
The majority of exchangers in these units are coolers, condensers or
tower reboilers. Carbon steel is the material of choice for the
process (usually shell) side of the coolers and condenser. The carbon
steel shells of these exchangers are subject to the same hydrogen
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induced cracking and blistering risk as are columns so HIC resistant
steels or Alloy 400 clad shells have been used as required.
The thin heat exchange tubing exposed to both the acid and cooling
water is generally made of CS or 70/30 CuNi. Some exchangers
may also be made with Alloy 400 tubing.
Reboilers are also usually all carbon steel unless dictated by the
corrosivity of the tubeside heating medium (steam, hot fractionator
streams). There typically have been minimal problems with these
exchangers.
In many cases the large first fractionator tower uses a fired heater as
the reboiler. Again carbon steel is the material of choice with
typically little problems associated with this metallurgy.
5.3.3 Piping
Carbon steel is the primary construction material used. Alloy 400
though is used in valve trim (or small diameter valves) to resist acid
erosion/corrosion. The hotter overhead piping of the regenerator/
rerun system is typically Alloy 400 to resist the hot acid. Gaskets are
typically also Alloy 400 in combination with PTFE or graphite.
5.3.4 Bolting
Carbon steel material used for bolting is usually A193-B7 or B7M.
The B7M bolting, which has a maximum hardness of 235 HB, is
used where enhanced resistance to hydrogen embrittlement is
desired. However, the lower minimum yield and tensile strength of
this material requires that greater attention is given to the proper
torque for loading in a flanged joint. Alloy material, such as Alloy
400 or Alloy C-276, is used in applications where greater corrosion
resistance is needed.
5.4 Corrosion Problems
5.4.1 Corrosion
Based on industry experience the following main problem areas
have been identified where corrosion may occur: acid relief system,
depropanizer feed and overhead systems, isostripper feed and
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overhead systems, acid regeneration/rerun tower and overhead
piping, propane/butane rundown systems and pump/valve castings.
Corrosion is caused by HF acid. Per Figure 5.2, the region of low
corrosion rates for carbon steel can be seen to be in the region of
high acid concentration and lower temperatures which is where HF
alkylation units are operated. Carbon steel forms a tight protective
iron fluoride scale that provides protection.
Hence the corrosion to carbon steel in the main acid section of the
plant is typically low. Here the exposure is at low temperatures with
either a hydrocarbon/acid emulsion or extracted circulating acid of
plant concentration (<2.5wt% water, > 80wt% acid concentration).
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Figure 5.2 Metals and Alloys for HF Acid 13
Iso corrosion regions where observed corrosion rates are 20 mpy (0.5mm/y) or less
A- N02200, N06030, N06600, N06985, N08007, N08020, N08825
B- N06022, N10276, N10665
C- Carbon Steel (May suffer hydrogen induced damage)
D- C70600, C71500, N04400, N24135, P00020, P04995, P07015,
R03600
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Refer to text on nickel rich and nickel based alloys for information on SCC. This
information is for guidance only. It represents low-flow, oxygen free, uncontaminated
conditions. Velocity and/or impurities may make these selections unsuitable.
The problems take place where the acid is hotter (such as in acid
regenerator/rerun systems) or is subject to water concentration
through the evaporating or condensing of the stream such as occurs
with the small amount (approx 1 wt%) dissolved or entrained into
the fractionation section. This leads to exposure through the more
corrosive zone per Figure 5.2. For this reason operators typically
restrict the amount of water in the acid (typically 2 to 2.5 wt%
maximum) to minimize the amount of corrosive acid/water mixture
that can be carried into the fractionation part of the unit.
Even though this corrosion was thought to be well defined, recent
experiences indicate that subtle differences in chemistry may affect
corrosion of carbon steel. A recent joint industry research program
examined this problem in depth as field corrosion losses were
appearing more frequently.
It has been reported that carbon steel components and welds that
contain higher amounts of residual elements (Ni + Cu + Cr) can
corrode uniformly at a greater rate in acid service. This may be due
to the increased use of recycled steel used by steel manufacturers.
Data to date indicates that this problem is prevalent in the hotter
medium (1-10%) acid area particularly in the primary fractionator
[or isostripper or depropanizer] feed piping. Acid here may be
condensing or evaporating through a 60% HF concentration range
that causes this corrosion. For this reason, some licensors and users
have specified lower residual element levels, of 0.2 wt% maximum
(Cu + Ni + Cr) carbon steel. The industry research program has
validated that the chemistry of carbon steels is an important
parameter that can affect localized corrosion. The program results
seem to indicate that the acid concentration at the pressure
conditions of the process will go through a 60% type acid regime
which can be locally corrosive. The program has identified that the
optimum carbon steel material (whether welds or components) to
contain less than 0.15 wt% Cu + Ni when the Carbon content is
greater than 0.18 wt%. If the carbon content falls below the 0.18
wt% then the Cu + Ni + Cr should be less than 0.15wt%. These
requirements are now incorporated into ASTM materials
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specifications
requirements.
Hydrofluoric Acid Alkylation Units
for
piping
components
as
supplementary
The alumina treating sections used to remove polymeric HF in
products, causes the formation of water and trace HF (<1 wt% HF).
It also has been reported that in this type of service has led to a weld
decay corrosion typical of dilute acids and that may be accelerated
by the galvanic reaction between high and low residual element
carbon steel components. Typically the lower residual element
carbon steel corrodes at a greater rate with a gradual increase to
maximum loss in the weld heat affected zone (HAZ). In the past it
was also thought that residual stresses related to welding may also
be contributing to this local weld decay problem. The joint industry
research program confirmed that the chemistry difference is
important and can cause localized corrosion by galvanic interaction.
The program also has validated that the PWHT condition of the
fabricated carbon steel has little impact on this localized corrosion
problem. Certain weld metals such as E6010 commonly used in root
welding were found to be more prone though to this localized
corrosion problem.
Alloy 400 as can be seen in Figure 5.2 provides a higher threshold
of corrosion resistance to HF acid. These rates are assumed to be in
oxygen free acid, which should be typical of an alkylation unit. If
oxygen ingress is allowed or ingress of cooling water is allowed
even this material will corrode at a greater rate.
Finally when Alloy 400 cladding is used, special care must be
exercised in the weld overlay or back cladding to achieve a
maximum Fe content since too high a Fe level in the deposited metal
will increase the corrosion rate in the HF acid.
5.4.2 Hydrogen Induced Damage
As part of the corrosion process, atomic hydrogen (H) forms and
evolves from cathodic areas of the metal as molecular hydrogen
(H2). When corrosion rates are high enough, desorption of
molecular hydrogen from the surface becomes rate controlling.
Atomic hydrogen builds up on the surface and will enter the steel
matrix where it can cause several forms of damage.
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Atomic hydrogen diffuses into the steel and forms molecular
hydrogen at voids, such as manganese sulfide inclusions or
lamination. Because of their larger size, hydrogen molecules cannot
diffuse out of the steel and accumulating hydrogen gas builds up
pressure deforming the surrounding metal. Blistering and cracking
are the result. During the manufacture of steel plate, contaminants
and slag residues segregate as inclusions and laminations in planes
located at 1/4, 1/2 and 3/4 of the plate thickness. Since corrosion
and, therefore, hydrogen diffusion proceeds from the inside of the
vessel, blisters will be generally found on the inside vessel wall. If
inclusions and laminations at the inner plane are patchy, atomic
hydrogen could diffuse through the plate thickness to the center and
outer planes of segregation. In the latter case, blisters would be
expected to show up on the outside vessel wall.
If there are several layers of inclusions and they are close together
smaller internal blisters can form at different planes. Cracking can
progress from the blister edges joining with other blisters causing
stepwise cracking through the thickness of the steel.
If high stresses (such as those due weld residual stresses or due to
stress concentration at other crack tips) are coincident with this,
cracking can become more oriented in the through thickness
direction of the plate and stress oriented hydrogen induced cracking
(SOHIC) results.
Finally in high strength steels (typically found in bolting, high
hardenability welds or heat affected zones) the atomic hydrogen
saturates the matrix and embrittles it making it susceptible to stress
cracking.
The amount of hydrogen penetrating in aqueous corroding solutions
into the steel is typically a function of corrosion rates Acidic
solutions such as HF acid can generate high hydrogen permeation if
high corrosion rates are allowed to remain. A tight adherent scale of
iron fluoride leads to a substantial reduction in corrosion and
hydrogen permeation and appears to be the primary reason for the
success of standard carbon steel in this service. It has been reported
that high hydrogen charging can occur after cleaning of surfaces
removing FeF scales for maintenance or inspection purposes. In
addition it has been reported that high charging and corrosion can
occur after hydrostatic testing of vessels due to the entrapment of
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water leading to corrosive low acid concentrations during the dryout
phase. In addition arsenic contamination in HF acid supply or due to
arsine (AsH3) in the feed has been reported to also increase the
hydrogen charging rate.
Hydrogen damage of carbon steel has caused damage to the
fractionation section of the alkylation plant. Overhead systems
appear to be particularly vulnerable. Damage to the high acid
reaction section has not been reported to be substantial.
5.5 Inspection and Mitigation
As a result of the experience with hydrogen induced damage in
alkylation units, inspections are generally carried out to monitor for
this problem. Common techniques include Wet Fluorescent
Magnetic Particle inspections for surface cracking on equipment
interiors and ultrasonics used to detect both subsurface blistering
and cracking. Acoustic emission may be used to screen vessels for
cracking activity during pressurization cycles.
Blistering can be vented to prevent crack growth. Cracks can be
ground out and weld repairs are done as needed. The extent of
repairs is assessed by appropriate engineering support and code
requirements. Heat treatment prior to welding, to bakeout absorbed
atomic hydrogen to prevent further cracking during repairs is often
done. Post weld heat treatment to temper hardenable welds and heat
affected zones and to reduce residual stresses are also often used. In
severe cases of hydrogen induced damage, equipment replacement
may be required. Special carbon steels with lower S levels, shape
controlling of the remaining S, normalized heat treatment and
hardenability limits are often specified for this service. In some
cases the use of Alloy 400 cladding is specified to totally eliminate
the problem. More detailed information on hydrogen induced
damage, inspection practices, repair techniques and construction
practices have been well summarized in references 1, 2, and 3.
A severe form of hydrogen induced damage is the embrittlement of
high strength alloy steels such as that used in bolting. The lower
hardness version of bolting (ASTM A193-B7M) is often specified
to resist this cracking, though even this alloy will crack after any
extended exposure. It is for this reason that heat exchangers usually
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are U-tube type bundles rather than of the bolted floating head cover
design.
Onstream ultrasonic and radiographic thickness measurement
techniques can be used to monitor for metal loss. This is of
particular value subsequent to the identification of a corrosion
problem in a system or for equipment that may be in the condensing
or evaporation zones where the acid may go through the corrosive
concentration state.
Alloy 400 in its cold worked or welded condition will stress
corrosion crack in HF acid particularly if oxygen enters the system.
Hence most users specify a stress relief heat treatment (1100 to
1200oF) after cold work or welding.
Certainly, the most effective mitigation approach is to use the proper
materials of construction and fabrication procedures along with
control of process variables within design guidelines.
5.6 Corrosion Control Measures
The primary corrosion control effort in the HF alkylation plant is the
limitation of feed water contents as this will dilute the circulating
acid and make it more corrosive. Rigorous frequent monitoring of
the feed moisture and the acid strength are done to monitor for this.
Monitoring for acid breakthrough in the product treating sections is
an important monitoring requirement to prevent corrosion in these
sections of the unit.
5.6.1 Corrosion Monitoring
Hydrogen-activity probes can be used to monitor for potential
hydrogen damage. Typical hydrogen-activity probes use a pressure
gage to measure the amount of hydrogen that has diffused through a
tubular CS specimen. These are not used typically in HF alkylation
due to the potential for leakage of HF and LPG components.
Other hydrogen activity measurement techniques are also available.
For example a sealed patch is mounted on the exterior surface of the
equipment item in suspected high hydrogen rates. The hydrogen
passes through the steel wall and is collected within a sealed patch.
Measurement of the hydrogen build-up can be by various means
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including vacuum loss or by reactions with solid state or wet
chemistry detectors. External mounted solid state detectors that are
periodic or continuous monitored have been a recent innovation.
Cooling water pH and/or Fluoride levels can be checked regularly to
monitor for possible exchanger leaks. Only a minor amount of
leakage can cause a dramatic drop in pH and increase in
corrosiveness leading to damage of water side components.
5.6.2 Corrosion Probes
Corrosion probes have had limited use in monitor ongoing corrosion
in HF alkylation units. The safety aspect of use in HF and LPG
discourage the use of retractable probes. In addition the build up of
iron fluoride scales may make operation and detection of events
difficult.
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Bibliography
1. NACE International REFINCOR, Petroleum Refining and
Gas Processing (STG 34), Refining Industry Information
Exchange (TEG 205X) Minutes., Houston, TX.
2. White, R.A. and Ehmke, E.F., “Materials Selection for Refineries and Associated Facilities”, Houston, TX: NACE International, 1991
3. NACE International, Technical Committee Report 8X294,
“Review of Published Literature on Wet H2S Cracking of
Steels Through 1989”, Houston, TX.
4. NACE International Technical Committee Report 8X194,
“Materials and Fabrication Practices for New Pressure Vessels Used in Wet H2S Refinery Service”, Houston, TX.
5. NACE International Standard Recommended Practice
(RP0296), “Guidelines for Detection, Repair, and Mitigation
of Cracking of Existing Petroleum Refinery Pressure Vessels
in Wet H2S Environments”, Houston, TX.
6. Effinger, R.T, Renquits, M.L., Wachter, A., and Wilson, J.G.,
“Hydrogen Attack of Steel in Refinery Equipment”, API Vol
31, pgs 108 - 133, Washington, D.C.: American Petroleum
Institute, 1951.
7. Bonner, W.A., Burnham, H.D., Conradi, J.J., and Skei,T.,
“Prevention of Hydrogen Attack on Steel in Refinery Equipment”, API Mid-year Meeting (May 1953), Washington,
D.C.: American Petroleum Institute, 1953.
8. API Recommended Practice 751, Second Edition, “Safe
Operation of Hydrofluoric Acid Alkylation Units”, Washington, D.C.: American Petroleum Institute.
9. Dobis, J.D., Clarida, D.R., and Richert, J.P, “A Survey of
Plant Practices and Experiences in HF Alkylation Units”,
Corrosion/94, Paper No. 511. Houston, TX: NACE International, 1994.
10. Hashim, H.H. and Valerioti, W.L, “Effect of Residual Copper, Nickel, and Chromium on the Corrosion Resistance of
Carbon Steel in Hydrofluoric Acid Alkylation Service,
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Hydrofluoric Acid Alkylation Units
Corrosion/93, Paper No. 623. Houston, TX: NACE International, 1993.
11. Forsen, O. et al, “Materials Performance in HF Alkylation
Units”, Corrosion/95, Paper No. 342. Houston, TX: NACE
International, 1995
12. Chirinos, G.,Trugoose, S., and Newman, R.C., “Effects of
Residual Elements on the Corrosion Resistance of Steels in
HF”, Corrosion/97, Paper No. 513. Houston, TX: NACE
International, 1997.
13. NACE International, Technical Committee Report 5A171,
“Materials for Receiving, Handling and Storing Hydrofluoric
Acid” , Houston, TX.
14. CMA, HFIPI, “Materials of Construction Guideline for
Anhydrous Hydrogen Fluoride.”, June 1994, Hydrogen Fluoride Industry Practices Institute, a subsidiary of the Chemical
Manufacturers Association.
15. MTI Publication MS-4, Materials Selector for Hazardous
Chemicals, Hydrogen Fluoride and Hydrofluoric Acid, St.
Louis, MO: Materials Technology Institute, 2003.
16. Gysbers, A, Clarida, D. Hashim, H., Chirinos, G., Marsh, J.,
and Palmer, J., "Specification for Carbon Steel Materials for
Hydrofluoric Acid Alkylation Units”, Corrosion/2003, Paper
No. 03651. Houston, TX. NACE International, 2003
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Chapter 6:Sulfuric Acid Alkylation
Units
Objectives
Upon completing this chapter, you will be able to do the following:
•
Differentiate between the two basic types of sulfuric acid alkylation units
•
Identify the four major sections found in both types of sulfuric
acid alkylation units and describe the process taking place in
each
•
Identify and discuss materials of construction in sulfuric acid
alkylation units
•
Identify and discuss corrosion problems that may occur in sulfuric acid alkylation units
•
Identify unit locations susceptible to corrosion problems and discuss methods that may be used to control corrosion
•
Identify corrosion monitoring methods, common probe locations, and the purpose for each
•
Identify unit areas that should be inspected and discuss inspection techniques commonly used.
6.1 Introduction
All refinery processes that use a mineral acid as a catalyst or treating
agent are subject to various types of corrosion. Sulfuric acid
alkylation is an example of such a process.
Corrosion and fouling should not cause serious problems in a welldesigned, operated, and maintained sulfuric acid alkylation plant.
However, these units often experience upsets and/or are operated
with process conditions that accelerate corrosion.
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Refinery cracking operations, primarily fluid catalytic cracking,
yield large quantities of light gases which may be converted to
gasoline blending components through an alkylation reaction. The
sulfuric acid alkylation process chemically combines a low-octane
olefin, which is usually butylene, propylene, or amylene, and an
isoparaffin, which is usually isobutane, in the presence of sulfuric
acid catalyst. The product is a higher octane alkylate—primarily
isooctane, or isoheptane.
Due to its high octane rating, the product is a particularly desirable
component of automotive gasolines. In California, alkylation is
important in the production of Clean Air Fuels. Several different
catalysts will promote alkylation, but hydrofluoric and sulfuric acids
are the most common. For the purposes of this discussion, we are
concerned only with sulfuric acid.
6.2 Process Description
The basic types of sulfuric acid alkylation units are shown in Figure
6.1 and Figure 6.2. Both types of units have four major sections as
follows:
•
Reaction
•
Treating
•
Fractionation
•
Refrigeration.
The principal differences between the two are based on the reactor
designs and the method in which refrigeration is accomplished.
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Figure 6.1 Typical Auto-Refrigeration Alkylation Plant with Stirred Reactors
Figure 6.2 Typical Effluent Refrigeration Alkylation Plant with Contactor-type
Reactor
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6.2.1 Reaction Section
In the reaction section, olefin feed is brought into intimate contact
with concentrated (93 wt% to 98 wt%) sulfuric acid at temperatures
between about 40ºF and 60ºF (5ºC and 15ºC). Mixing maximizes
acid and hydrocarbon contact. The olefin feed may be pretreated
prior to entering the reactor. For example, caustic washing may be
done to remove sulfur; coalescers may be used to remove water,
reducing detrimental acid dilution; or filters may be used to
eliminate solids which could cause plugging and fouling problems.
Water, velocity, and high temperatures are the principal causes of
corrosion.
In the auto-refrigerated stirred reactor design (Figure 6.1),
alkylation occurs in multiple compartment reactors, which are
agitated using relatively low-speed, paddle-type mixers in each of
the compartments. The isobutane and acid are mixed and added to
the reactors separately from the olefin feed. Heat of reaction is
removed by allowing a portion of the light hydrocarbon to vaporize
and auto-refrigerate.
In the effluent refrigerated contactor design (Figure 6.2), the acidfeed emulsion is mixed in a large reactor vessel. The acid and olefinisobutane mixture is added separately at the eye of a mixing
impeller, which maintains the emulsion and moves it along the
reactor. Refrigerant is circulated through heat exchanger tubes in
the reactor to remove the heat of reaction.
Following the reactor, the acid-hydrocarbon emulsion is separated
in a settler. A majority of the spent acid is returned to the reaction
stage with fresh, concentrated make-up acid. A small portion of the
acid is purged to maintain the acid concentration. Alkylation
reduces the concentration of the sulfuric acid, thus creating lower
concentration spent acid of 88 wt% to 90 wt% concentration.
6.2.2 Treating Section
In the treating section, residual acid catalyst and acidic by-products
are removed from the reactor effluent by one or more of several
consecutive treating steps, including acid washing, neutralization
with dilute caustic (NaOH), and water washing. A typical system is
shown in Figure 6.3.
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Figure 6.3 Typical Caustic and Water Wash Facility
Mixing is often accomplished using in-line mixers followed by
drums to separate the alkylate from the caustic and water. Some
plants have also installed acid wash facilities to extract acid esters
from the reactor product, minimizing the impact on downstream
fractionation facilities.
6.2.3 Fractionation Section
In the fractionation section, shown in Figure 6.4, alkylate is
separated from butane and excess isobutane. Following the settler
and treating section, the reactor products are usually sent in
succession to a deisobutanizer and a debutanizer where isobutane,
normal butane, and alkylate product are separated. In some
locations, alkylate is further fractionated to provide flexibility in
product use. In addition, to use as a fuel blending stock, alkylate
may be used as a feed to solvent production units. Isobutane is
recycled to the start of the process.
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Figure 6.4 Typical Fractionation Facility
6.2.4 Refrigeration Section
Because the alkylation process is exothermic, refrigeration is used
to limit temperatures to a favorable operating range, generally in the
40ºF to 60ºF (5ºC to 15ºC) range. Refrigeration is accomplished in
one of two ways depending on the reactor type. Where stirred autorefrigerated reactors are used, cooling is accomplished by controlled
vaporization of a portion of the light hydrocarbon contained in the
reactor as illustrated in Figure 6.1, Typical Auto-Refrigeration
Alkylation Plant with Stirred Reactors. This approach is known as
auto-refrigeration.
In the contactor design, isobutane becomes the refrigerant for the
cooling coils of the contactors as shown in Figure 6.2, Typical
Effluent Refrigeration Alkylation Plant with Contactor-type
Reactor. In both types of systems, flashed vapors are recompressed
and propane is removed before recirculating the remaining stream to
the reactor. The depropanizer feed is often caustic and water washed
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to remove acid contamination in a treating system similar to the one
on the reactor product.
6.3 Materials of Construction
Sulfuric acid alkylation units are built primarily of carbon steel,
typically with a 1/4-in. (6mm) corrosion allowance in the areas
where sulfuric acid is present. In the fractionation section, a 1/8inch corrosion allowance may be used for towers. Carbon steel is
commonly used to construct these units because it resists corrosion
from concentrated acid at low (near-ambient) temperatures.
Carbon steel welds likely to be contacted by sulfuric acid may in
some cases be postweld heat treated to minimize preferential
corrosion of welds and weld heat-affected zones. Weld root beads
are often made by using gas tungsten arc welding (GTAW) to
provide high quality welds. These welds offer limited slag and weld
deposit penetration into the line, minimizing turbulence that can
increase corrosion rates. SMAW (stick) welds can have dropthrough, which creates turbulence and subsequent corrosion, and are
not recommended. Cold-worked metal (usually bends) is often
stress relieved. Bevel any transition in piping thickness.
In high-concentration sulfuric acid, carbon steel depends on a film
of iron sulfate for corrosion resistance and, if high-flow velocities
and turbulence destroy this film, corrosion can be quite severe. For
this reason, flow velocities of any streams containing significant
amounts of concentrated sulfuric acid are usually limited to
velocities of 2 ft/s to 3 ft/s (0.6 m/s to 0.9 m/s). Special alloys are
used for valves, pump internals, and injection and mixing nozzles.
Piping just upstream and downstream of the caustic and wash-water
injection points in the treating section often requires selective
alloying.
Where excessive corrosion of carbon steel is encountered, Alloy 20,
an austenitic alloy especially designed to resist corrosion by sulfuric
acid--Ni-Mo Alloy B-2, Ni-Cr-Mo Alloy C-4 or Alloy C-276, high
silicon cast iron, or high-nickel cast iron--are usually suitable
alternatives. It should be noted that Alloy B-2 is susceptible to
higher corrosion rates in the presence of oxidizing agents in the acid
or air contamination.
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In practice, valves and pumps in concentrated and spent sulfuric
acid service often are made from solid Alloy 20 or its cast similar
alloy, CN7M. For hydrocarbon streams containing traces of
concentrated or dilute sulfuric acid, steel-body valves with Type 316
stainless steel or alloy 20 trim can be used. In this service, steel
pump casings, sometimes weld overlaid with aluminum bronze,
have been used successfully. High-silicon iron pump impellers are
often used.
Piping for hydrocarbon/acid mixing lines ahead of the reactors may
require Alloy 20 because water contamination of feed stocks can
cause severe corrosion of carbon steel. Ni-Cu Alloy 400 has been
found useful for reactor effluent lines around the point of caustic
injection. Alloy 400 and titanium grade 2 have been used as a
replacement for carbon steel or admiralty brass for tubes in
overhead condensors.
In general, most organic coatings are not resistant to concentrated
sulfuric acid. Fluoropolymers such as PTFE have excellent
resistance, however, and are used extensively for gaskets, pump and
valve packing, and mixing nozzles.
6.4 Materials and Corrosion Problems
Under ideal operating conditions, few corrosion problems occur.
Many streams, however, contain potentially troublesome
compounds and any meaningful corrosion control program must be
aimed at controlling these compounds through suitable process
changes. Except where uncontrolled acid dilution occurs, most
corrosion problems occur in the fractionation section. Much of the
damage will be found in reactor-effluent lines, overhead systems,
and reboilers. Damage can be especially severe in deisobutanizer
(DIB) overhead systems. Compounds responsible for corrosion are
either contaminants in feed stocks or reaction by-products contained
in the reactor effluent.
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6.4.1 Sulfuric Acid Corrosion
6.4.1.1 Acid Concentration
The principal corrosive in alkylation units is sulfuric acid (H2SO4),
which is used as a catalyst in the alkylation reaction. Within the
typical ranges of H2SO4 concentration, temperature, and velocity,
carbon steel can be used satisfactorily for a large part of the unit.
Mixtures of sulfuric acid and hydrocarbon are generally less
corrosive than fresh acid. Sulfuric acid corrosivity is not linear with
concentration, however. Diluted acid is much more aggressive than
concentrated acid. For example, carbon steel is satisfactory above
65 wt% concentration, but it cannot be used below 65 wt%.
Acid corrosion can be particularly troublesome during unit
shutdown and preparation for entry. Without proper operating
precautions, diluted acid can be present, resulting in very high
corrosion rates of carbon steel. To compound this problem, dilution
of acid is exothermic, and the temperature increase can further
accelerate corrosion. (See Chapter 1 for more information).
6.4.1.2 Acid Temperature and Velocity
Temperature and velocity also have a direct relationship to corrosion
rates, and the rates can increase substantially if they become
excessive. As a result, control of the velocity within specific limits
is a normal practice, and the temperature is usually kept as low as
possible. Typical velocity limits are 2 ft/s to 3 ft/s (0.6 m/s to 0.9 m/
s) for carbon steel in sulfuric acid. Higher velocities may be
permissible in the low-temperature sections of the plant. Alloy
materials will be required at some higher velocity areas and in some
spent acid systems, especially those where the acid may be heated.
Particularly troublesome locations for erosion-corrosion, even when
velocities are well controlled, are mixing tees, throttling valves,
restriction orifices, check valves, and low-point bleeders where high
turbulence is likely to occur. Under such circumstances, it is
common to specify Alloy 20, Alloys B-2, C-4, or C-276, or PTFE
components in place of carbon steel.
It was reported at an NACE International T-8 corrosion information
exchange that high nickel-iron contactor reactor impellers can
experience accelerated tip erosion. Two plants reported similar
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excessive erosion of the impellers. The solution developed for this
type of erosion was to hardface the impeller tips with a material
such as hard-facing Alloy 21.
6.4.1.3 Acid Dilution
Control of acid concentration is very important, not only from the
process aspect, but also to minimize excessive corrosion. For
example, when the acid strength drops substantially below 88 wt%,
a phenomenon called acid runaway can take place. During acid
runaway, reactions other than alkylation occur. Polymerization
forms large quantities of acid-soluble materials. Such reactions
drastically raise the acid diluents. Under such extreme conditions, it
is not possible to maintain the acid strength, even with adding fresh
acid at the maximum rate possible. Esters are also formed which
cause high corrosion rates in equipment downstream of the settlers.
In addition, emulsions can carry acid downstream to areas not
designed for it.
6.4.1.4 Hydrogen Grooving
A special problem associated with sulfuric acid corrosion is called
hydrogen grooving. It can occur in pipes and tanks where sulfuric
acid is stagnant or slow moving. Hydrogen grooving is a form of
localized, accelerated corrosion which can occur in mixed-phase
acid piping, manways of vessels, and especially above some kinds
of nozzles in acid storage tanks. Hydrogen generated by sulfuric
acid corrosion rises along the vessel, tank, or pipe wall and removes
protective sulfate scales. Usually a pattern of parallel grooves is
observed, thus the name hydrogen grooving.
Corrosion due to hydrogen grooving occurs at a rate faster than
H2SO4 corrosion. In one publicized case, accelerated corrosion and
hydrogen grooving caused an acid tank to split vertically in a line
coincident with the position of a flush-mounted, side-entry acid inlet
nozzle. Such a failure could also have occurred with a top-entry
nozzle that discharges near the tank wall. These failure types can be
avoided by designing nozzle discharge locations to avoid tank walls.
In piping systems, hydrogen grooving has been observed at elbows
at the top of a vertical piping run and along the pipe wall leading up
to that point.
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6.4.2 Feed Contaminants
Typical feedstock contaminants include:
•
Water
•
Mercaptans
•
Diolefins.
When present in sufficient quantity, contaminants tend to stabilize
the acid emulsion, consume acid by water or polymer dilution, or
react with the acid to produce troublesome by-products. These can
ultimately result in corrosion problems downstream of the reactor if
improper levels of contaminants are allowed to enter the system.
Water enters the reactor with butane-butylene feed. It may also be
present in recycled isobutane because reactor effluent is caustic
treated and water washed. The amount of dissolved water in
feedstocks depends on the temperature, on average doubling for a
30ºF (16ºC) increase in temperature. The amount of entrained water
can be controlled to some extent by modifying the feed-treating
operations.
Mercaptans and other sulfur compounds in the feed normally are
removed by caustic treating and water washing, but residual
amounts may still remain.
Diolefins originate from catalytic cracking operations and cannot
normally be removed from alkylation feed streams without special
processing. Butadiene polymerizes forming acid-soluble
compounds. Formation of these compounds reduces acid
concentration and increases make-up acid requirements. Very high
levels of diolefins make the plant more susceptible to upsets
resulting in acid runaway.
6.4.3 Acid and Neutral Esters
Water, mercaptans, and diolefins not only dilute and consume
sulfuric acid catalyst, but also increase the amount of undesirable
by-products in the reactor effluent. These include entrained sulfuric
acid catalyst as well as acidic alkyl sulfates and neutral dialkyl
sulfates from secondary alkylation reactions. Both acid and neutral
esters of hydrocarbon and sulfuric acid are produced in alkylation
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reactors. High space velocity reactors and high temperatures,
resulting from poor operating conditions, favor ester formation.
6.4.3.1 Acid Esters
Reactor effluent normally contains 30 ppm to 100 ppm of alkyl acid
sulfates, largely dissolved in the hydrocarbons. However, they may
be greater due to entrained sulfuric acid. The acid esters will be
corrosive to equipment upstream of the caustic wash facilities.
Typically, the reactor product pump and the reactor product
exchanger are affected by these acid esters. The caustic wash will
eliminate corrosion of downstream equipment by neutralizing the
acid esters as well as small quantities of acid carried over from the
settler. However, the caustic wash is generally low in alkalinity and
can easily be overwhelmed by carryover of concentrated acid.
Monitoring of the neutralization circuit pH is critical.
Alkyl acid sulfates are not corrosive after neutralization with caustic
in the treating section. If not effectively removed in the caustic
wash, they may revert to acid at the high temperatures encountered
in reboilers and cause corrosion problems in towers and overhead
systems, as well as fouling problems in reboilers. Upsets in reactor
operations increase alkyl acid sulfate formation. Upsets in the
treating section increase carryover of water and neutralized esters.
6.4.3.2 Neutral Esters
Reactor effluent also contains 10 ppm to 150 ppm of dialkyl
sulfates. These neutral esters are largely dissolved in the
hydrocarbon phase and ordinarily cannot be neutralized or removed
by caustic and water washing. Breakdown of these esters can occur,
starting at about 170ºF (75ºC), when they are heated in the
deisobutanizer preheater or reboiler. This decomposition can then
cause corrosion and fouling problems similar to those caused by
alkyl sulfates. Dialkyl sulfates appear to be especially troublesome
in the alkylation of propylene feed.
Decomposition of these esters forms SO2, which will combine with
water and cause acid corrosion in feed preheaters. Corrosion can
also occur in the reboilers and in the deisobutanizer overhead
condenser where condensation can occur. The residues that remain
in the reboiler from the coking of hydrocarbon on the hot tubes of
the reboiler can cause fouling and overheating, leading to failure of
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the tubes. The polymeric compounds are responsible for fouling of
the reboilers.
When alkyl and dialkyl sulfates decompose in fractionation section
reboilers, sulfur dioxide (SO2) and polymeric compounds are
formed. The SO2 formed from the reduction of the sulfates rises in
the tower and can cause problems in the overhead system due to the
low pH water. SO2 combines with water and forms sulfurous acid in
the top tower sections, the overhead condensers, and reflux drums.
Although the pH of the overhead water is usually 6 to 7, lower pH
could be a symptom of the presence of esters.
6.4.4 Acid Carryover
Downstream of the acid/hydrocarbon separator, the reactor effluent
normally contains 50 ppm to 500 ppm of acid catalyst. Under
normal circumstances, and with proper contacting, the caustic and
water wash systems of the treating section remove the trace acid.
During upsets, however, large slugs of acid may pass through the
treating section essentially un-neutralized. In general, acid will go
where the water goes. When the water condenses, the acid will
concentrate and cause corrosion. Acid slugs can quickly cause
considerable corrosion damage because the high boiling point
(330ºF to over 600ºF [165ºC to 315ºC]) and the high specific gravity
tend to concentrate sulfuric acid in tower bottoms and reboilers of
the fractionation towers.
Acid carryover is also a concern in the refrigeration systems of
sulfuric acid alkylation units. While the corrosion rate of the sulfuric
acid is generally tolerable, accumulated corrosion over many years
can go undetected since acid may accumulate locally unnoticed.
Designing vapor systems in particular to minimize low points can
help reduce acid collection.
6.4.5 Corrosion Under Insulation
Equipment in the unit which operates below the ambient air
temperature may be vulnerable to external corrosion. When
breaches of the insulating system and vapor barrier occur, the low
metal temperature will cause moisture to condense. This, in turn,
can cause localized corrosion under insulation (CUI) where water
may collect. It is important to recognize that the point of the
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insulation breach is often not the same location where water will
collect and cause corrosion.
6.4.6 Fouling Problems
Fouling problems often accompany corrosion in the fractionation
section, primarily in reboilers of various towers. High vaporization
rates make reboilers particularly vulnerable to fouling. As discussed
previously, fouling is caused by alkyl and dialkyl sulfates in the
reactor effluent which decompose and polymerize at temperatures
above 250ºF (121ºC). The deposits vary from varnish-like coatings
on relatively cool surfaces to asphalt and coke-like deposits on hot
surfaces. Insoluble corrosion products and inorganic salts often
accumulate in reboilers and add to the bulk of deposits, with
polymers acting as binders.
Fouling occurs to a lesser extent in the lower section of certain
towers, particularly the rerun and deisobutanizer towers.
Antifoulants may be injected into the tower feed streams to
minimize this problem. Reboilers are protected at the same time
because antifoulants tend to stay with the heavier hydrocarbon
fractions.
6.5 Corrosion Control Measures
Good process control plays an important part in avoiding corrosion
problems through good feed preparation and by maintaining acid
concentration. Feed preparation includes the removal of
contaminants by caustic treating, water washing, coalescing, and
filtering. Alkylation plants that operate with healthy conditions do
not need the use of any special corrosion control additives.
However, as esters increase with increasing throughput and more
severe alkylation conditions, corrosion control can be more of an
issue.
6.5.1 Reactor Section Corrosion
Corrosion of reactor effluent lines downstream of the effluent
treating section is caused by excessive amounts of entrained acid
catalyst or the presence of esters and can usually be corrected by
suitable changes in the caustic treating and water washing
operations. Otherwise, reducing velocities or partially replacing the
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carbon steel effluent lines with Type 316L stainless steel or alloy 20
may be required as a long-term solution to the problem.
6.5.2 Tower Overhead Corrosion
To control excessive corrosion in fractionation section overhead
systems, the use of caustic and water wash of the reactor product is
of primary importance to remove acidic contaminants. However,
tower overhead corrosion may still occur as a result of acid
carryover and ester decomposition. In tower overhead systems,
neutralizing and filming amine corrosion inhibitors have sometimes
been used. However, the application of treating chemicals to the
deisobutanizer overhead system must be approached cautiously as
recirculation of the amines with the isobutane may contribute to
problems in the reaction section. Such problems are typically not
associated with chemical treatment of the debutanizer overhead
system.
Because a neutralizer has the benefit of helping control corrosion in
downstream equipment by chemically reacting with the corrosive,
they may more commonly be added to the deisobutanizer feed to tie
up acid released during decomposition of esters. This approach to
neutralizer usage avoids isobutane contamination by the amine. In
this operating scenario, fouling by neutralizer salts of the reboiler
may occur, but these may be removed by water washing the tower.
If their use is determined to be acceptable from an operations
standpoint, filming amine inhibitors are typically injected into the
overhead line at rates ranging from 5 ppm to10 ppm by volume,
based on the amount of hydrocarbon condensed in the reflux drum.
In order to reduce corrosion rates and inhibitor consumption as
much as possible, overhead water condensate can be neutralized to a
pH of between 6 and 7. Both neutralizing amines and ammonia
have been used, but in some cases ammonia has caused stress
corrosion cracking of admiralty brass tubes in overhead condensers.
Corrosion control in the depropanizer overhead is most effectively
achieved by keeping the system dry. Wet systems vulnerable to acid
carryover have sometimes been treated before the depropanizer with
caustic wash to remove acid contamination and water washed to
remove caustic. Some plants use electrostatic precipitators in
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Sulfuric Acid Alkylation Units
separation vessels following caustic washing to improve caustic
removal from product.
6.5.3 Reboiler Corrosion and Fouling Control
Reboiler corrosion is most easily avoided by keeping reboilers free
of fouling deposits and minimizing the presence of esters. In severe
cases, injection of filming amine corrosion inhibitors into the
reboiler feed line has proved to be beneficial.
Process changes designed to control corrosion problems will also
minimize fouling problems. In addition, periodic blowdown and
water jetting are beneficial in resolving the fouling problems of
reboilers. In more severe cases, antifoulants can extend operating
runs by keeping potential foulants dispersed in the hydrocarbon
phase. Maximum benefits are realized by continuous injection into
the tower bottoms line ahead of the reboiler at rates ranging from 5
ppm to 20 ppm by volume, based on the amount of liquid
hydrocarbon entering the reboiler. Antifoulants are usually effective
in preventing the formation of hard, baked-on deposits on heat
exchanger surfaces. As a result of their use, reboiler bundles may be
cleaned more easily by steaming or water washing.
6.5.4 Acid Tanks
NACE SP02941 (current edition), “Design, Fabrication, and
Inspection of Tanks for the Storage of Concentrated Sulfuric Acid
and Oleum at Ambient Temperatures,”(Houston, TX., NACE)
which is included as Appendix M, is a valuable reference on H2SO4
acid storage tank design to minimize corrosion. SP0294 (current
edition) includes the following recommended design details:
•
Tanks should be fitted with a top inlet nozzle.
•
Inlet nozzle should be placed away from the side wall and be fitted with a section of pipe protruding at least 150 mm (6 in.) into
the tank or with a dip tube terminating no less than 600 mm (24
in.) from the tank floor.
1.
NACE International publishes three classes of standards: standard practices, standard
material requirements, and standard test methods. Until June 23, 2006, NACE published standard recommended practices, but the designation of this type of standard was changed to simply standard practice. New standards published after that date will carry the new designation
(SP), and existing standards will be changed as they are revised or reaffirmed.
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•
Splash plates should be provided beneath side outlet nozzle piping and inlet nozzle dip tubes.
•
Manways and side nozzles should be lined or weld overlaid with
alloy to prevent hydrogen grooving.
•
Valves, inlet and outlet pipes, vents, and wear or splash plates
should be a corrosion-resistant alloy, such as alloy 20.
The internal upper shell, roof, and roof structure exposed to acid
vapors may be coated. Components exposed to acid vapors are more
vulnerable to corrosion than those immersed in acid. Coating
manufacturers should be consulted on appropriate coatings for this
application. Where feasible, the roof supporting structure may be
external to the tank to minimize internal structure components,
which are difficult to protect with coatings.
6.5.5 Corrosion Control During Unit Shutdowns
Corrosion can be particularly troublesome during unit shutdown as
equipment is rinsed. Acid dilution increases the corrosion rates on
carbon steel through the effect of the reduced concentration as well
as through increasing temperature during acid dilution.
Consequently, proper draining and flushing procedures are needed.
Dilute acid can form, which is corrosive to carbon steel. To gas free
the unit, equipment is often flooded with water until the pH of the
drained water is greater than 6.0. The equipment is then drained as
soon as possible.
Flushing of the reactor, settler, tank, and other equipment with low
strength caustic is often done during turnarounds before water
washing. Since much of this equipment is not postweld heat treated,
control of caustic strength is important. At a recent NACE
International meeting, one company reported foaming the
neutralizing solution to reduce the required volume to 10% of their
normal usage. They also added 0.1 vol% of an acid indicator to
serve as a visual indicator of the neutralization process.
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Sulfuric Acid Alkylation Units
6.5.6 Corrosion Under Insulation (CUI)
CUI is usually controlled by the application and maintenance of
coatings on equipment subject to this phenomenon. A large number
of papers have been published on the subject of CUI prevention.
NACE Standard, RP0198 (current edition), “The Control of
Corrosion Under Thermal Insulation and Fireproofing Materials—A
Systems Approach,” (Houston, TX., NACE) provides information
on CUI prevention methods and is included in Appendix S.
On cold-service equipment, which normally operates below ambient
temperatures, the insulation system should be designed with an
effective vapor barrier. Protrusions through the insulation need to
be well sealed, and the sealant maintained, to avoid moisture
ingress. Insulation damage should be repaired promptly.
6.6 Corrosion Monitoring
To monitor for corrosion and to warn operators of corrosive
conditions, corrosion probes may be used. Some common locations
for probes are listed in Table 6.1 on page 19. Unusual corrosion
activity should be carefully evaluated and corrective measures
taken.
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Table 6.1: Common Corrosion Probe Locations in Sulfuric Acid
Alkylation Units
Corrosion Probe Location
Effluent piping from settler to deisobutanizer caustic wash
Feed piping to deisobutanizer
Effluent piping from deisobutanizer overhead condenser
Effluent piping from debutanizer reboiler
Effluent piping from depropanizer overhead
condenser
Purpose
Determines whether excessive acid is being
carried over
Helps determine if caustic wash is controlling corrosion that could be caused by acid
entrainment
Determines whether caustic wash is controlling acidic species in tower feed and/or
neutral esters may be decomposing to SO2
Helps determine if caustic wash is controlling corrosion or if caustic carryover is
occurring
Determines whether caustic wash is controlling SO2/esters in refrigerant purge
stream and/or neutral esters may be decomposing to SO2
In addition to corrosion probe monitoring, specific process streams
are normally sampled for chemical analyses as a further check on
corrosion control. Typical samples are listed in Table 6.2.
Table 6.2: Common Stream Analyses for H2SO4 Alkylation
Sample
Spent acid from acid settler
Analysis
% free acid
Water draw-off from water wash
circulation loop
Water draw-off from deisobutanizer overhead drum
Water draw-off from depropanizer
overhead drum (for systems with a
treating system on the feed to the
depropanizer)
pH
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pH
pH, if water present
Purpose
Warns when acid concentration
is low
Warns when acid carryover is not
being neutralized
Values under 5.5 to 6.0 indicate
corrosive conditions
Values under 5.5 to 6.0 indicate
corrosive conditions
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6.7 Inspection
6.7.1 Reaction Section
In the reactor feed system, only routine inspection of equipment is
required because of the relatively mild conditions. The reactor feed
chiller and downstream piping and equipment operated at low
temperature are subject to CUI. Regular inspections for the
insulation integrity and CUI are warranted.
In the reactors themselves, the inlet and outlet nozzles are of
particular concern. The reactor and settler are also vulnerable to
CUI. Internals of reactors, particularly wear plates, feed nozzles,
mixers and impellers, and the vessel shell near mixers/impellers are
of special interest. Velocity in the settler is generally low so
turbulence-related corrosion should be minimal.
Acid-containing equipment most vulnerable to corrosion includes
the following:
•
Pump discharge piping
•
Spent acid piping
•
Turbulent areas, such as elbows (include high points where
hydrogen grooving has been observed), tees, and reducers
•
Valves, particularly control valves, check valves, valves used for
throttling, and small connections (low points)
•
Dead legs in piping systems
•
Uninsulated/uncoated cold steel
•
Insulation integrity.
The spent acid system generally requires a comprehensive
inspection program, particularly of carbon steel equipment, because
it handles ambient temperature, reduced-strength acid without
hydrocarbon. Although hot spent acid is much more corrosive than
cold, cold systems should also be thoroughly inspected, particularly
at turbulent areas.
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Periodic onstream monitoring can be carried out using
nondestructive evaluation (NDE) methods, such as radiography.
Wall thickness information obtained using conventional
radiography may be limited with larger acid-filled lines, and higher
energy sources may be needed.
Cold service equipment and piping does not lend itself well to
frequent ultrasonic (UT) thickness measurements because such
testing would require a break in the insulation vapor barrier, which
could permit water ingress, condensation, and CUI. However, colder
systems are generally less vulnerable to internal corrosion so less
frequent measurements are suitable. Often, insulation removal and
visual and UT inspection are considered the most reliable methods
to inspect for CUI. However, radiographic techniques are being
used that can provide the type of wide-area inspections that are
needed for this form of corrosion.
6.7.2 Treating Section
Mixing points have been a source of accelerated corrosion in a
variety of refinery services. Inspection of the caustic and water wash
mixing points for accelerated corrosion is important in the
alkylation unit. The mixing points in the deisobutanizer feed system
are particularly important. If excessive acidity is present, the mix
points can experience low pH and wide pH variability, and even
materials like alloy 20 may not be suitable.
6.7.3 Fractionation Section
Hot equipment downstream of the caustic and water wash facilities,
which has not been postweld heat treated, may be vulnerable to
caustic stress corrosion cracking due to caustic carryover. While the
inspection of piping welds for such cracking is difficult, vessels
such as the deisobutanizer feed heater, deisobutanizer tower, and the
tower reboiler should be inspected if caustic carryover can occur.
The deisobutanizer tower, reboiler, and overhead condenser are also
vulnerable to accelerated corrosion, which may be localized, due to
acid carryover or the breakdown of esters.
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6.7.4 Refrigeration Equipment
Refrigeration equipment is naturally subject to CUI. Inspection for
CUI includes radiographic methods, but the most reliable method is
still often considered to be insulation removal and visual inspection.
Visual inspections should focus on insulation integrity.
Equipment should be inspected for signs of corrosion due to acid
carryover. Specific locations of concern include low points, the
refrigeration compressor knockout drum, and the refrigeration
condensers.
6.7.5 Acid Tank
Inspection of acid tanks should be in accordance with API 653,
“Tank Inspection, Repair, Alteration, and Reconstruction,”
(Washington, D.C.: American Petroleum Institute, 1995). However,
corrosive conditions in the tank may warrant more frequent
inspections than API 653 intervals might suggest. Key inspection
locations include:
•
UT measure of tank shell and nozzles/manways in the vicinity of
and above acid inlet nozzles
•
Inspect vapor space for corrosion and lining integrity
•
Measure tank floor in the vicinity of acid outlet nozzle.
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Chapter 7:Hydroprocessing Units
Objectives
Upon completing this chapter, you will be able to do the following:
•
Describe, in general terms, the purpose of hydroprocessing units
and how they work
•
Identify the major types of hydroprocessing units, differentiating
among them
•
Identify and discuss the process conditions present in hydroprocessing units that lead to corrosion mechanisms in these units
•
Identify and discuss eight common types of corrosion that may
occur within hydroprocessing units
•
Identify techniques that may be used to mitigate or prevent corrosion in hydroprocessing units
•
Identify and discuss two different material property degradation
mechanisms that occur in some plants
•
Identify techniques that may be used to avoid material property
degradation
•
Identify appropriate construction materials for eleven corrosionprone areas within a hydroprocessing unit.
7.1 Introduction
As petroleum moves through refinery processing units, various
contaminants may degrade equipment or even the finished product.
Hydroprocessing units improve hydrocarbon feedstocks by
removing contaminants and/or by converting heavier feeds into
more valuable, lighter products.
The chemical reactions in these feedstocks occur, in the presence of
catalysts, in a hydrogen-rich environment at high temperatures and
at high pressures.
Types of hydroprocessing units are:
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Hydroprocessing Units
•
Hydrotreaters (including hydrodesulfurizers)—Remove sulfur
and/or nitrogen
•
Hydrocrackers—Crack heavier feeds into products with lower
boiling points
•
Hydrogenators—Add hydrogen
hydrogen-deficient hydrocarbons
•
Hydrofiners—Remove color bodies.
to
unsaturated
or
other
Sulfur and nitrogen react with hydrogen to form hydrogen sulfide
(H2S) and ammonia (NH3) within a hydrotreater unit. These
compounds have a significant effect on corrosion and materials
selection for various types of hydroprocessor units. The bulk of this
chapter will be devoted to identifying various types of corrosion
occurring in hydroprocessing units and the selection of appropriate
materials to guard against them.
7.1.1 Hydroprocessing
The two most common types of hydroprocessing units are the
hydrotreater and the hydrocracker.
Sometimes the two processes are combined, with the first stage
(hydrotreating) removing contaminating agents and the second stage
acting as a hydrogenator or hydrocracker.
The most important distinction between these stages in terms of
corrosion is that the feed to a hydrotreater contains considerable
amounts of sulfur and nitrogen, while the feed to the second-stage
hydrocracking section does not. Since sulfur, nitrogen, and
ammonia typically reduce the activity of the second-stage catalyst,
most of these contaminants are removed during the hydrotreating
stage. As a result, fewer corrosion considerations are taken into
account and fewer upgraded materials are used in second-stage
hydrocrackers compared to first-stage or single-stage designs.
Single-stage hydrocrackers are a high-operation treatment that not
only hydrotreats, but also converts heavier hydrocarbons into lighter
products and hydrogenates the converted hydrocarbons.
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7.1.2 Hydrotreating
Feedstocks coming into refinery units often contain heavy amounts
of sulfur compounds as part of the stream. Hydrotreating has
become increasingly effective in breaking out these sulfur products
and cracking heavy molecules in the feed to produce lighter product
oils. The actual amount of impurities removed depends on the feed
and end product specifications. Figure 7.1 depicts a common
hydrotreater unit.
Figure 7.1 Simplified Flow Diagram of Hydrotreater Unit
The reactor contains catalyst and typically operates at pressures
between 42 kg/cm2 to 141 kg/cm2 (600 psi to 2000 psi) and
temperatures between 371°C to 454°C (700°F to 850°F). Hydrogen
is injected into the feed, which is heated in feed/effluent exchangers
and a furnace. Within the reactor, or sometimes multiple reactors,
sulfur and nitrogen compounds are converted to hydrogen sulfide
(H2S) and ammonia (NH3). The reactor effluent is cooled by
passing through a series of heat exchangers and air coolers then sent
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to separator vessels. Usually, water is injected to control fouling or
corrosion upstream of the air coolers.
Gases from the separators—hydrogen, some very light
hydrocarbons, and a high percentage of hydrogen sulfide—are
recycled back to the feed through a compressor. Some additional
hydrogen is usually added at this point. The liquid hydrocarbons
generated from the separators are sent through pressure let-down
valves to the fractionation section of the unit.
The water phase from the separators contains almost all of the
ammonia formed in the reactors. The dissolved H2S in this water
combines with the NH3 to form ammonium bisulfide (NH4HS) as
well as inorganic salts, such as ammonium chloride. Traces of
cyanide may also be present.
7.1.3 Hydrocracking
Hydrocracking is the process of cracking down compounds, with
catalysts, in the presence of hydrogen. Increasing demand for
middle distillates and cleaner-burning transportation fuels has
driven refiners toward increased conversion capacity through
hydrocracking or two-stage processors. One of the benefits of
hydrocracking is that the process does not result in a lot of bottomof-the-barrel leftovers, such as coke or pitch.
In a single-stage hydrocracking unit, the feedstock is mixed with
hydrogen, heated, and passed through catalyst-filled reactors. See
Figure 7.2.
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Figure 7.2 Flow Diagram of Single-Stage Hydrocracking Unit
The reactor effluent is then cooled. The gas phase, which is
primarily hydrogen, is recycled back to the feed. The liquid
hydrocarbon is sent on to the distillation section.
Typical reactor pressures in a hydrocracking unit are 106 kg/cm2 to
211 kg/cm2 (1500 psi to 3000 psi), with temperatures in the range of
343°C to 454°C (650°F to 850°F).
7.1.4 Variations on Hydroprocessing
Some units differ from the two flow schemes depicted in Figure 7.1
and Figure 7.2. In some vacuum residual desulfurizers, the reactor
effluent enters the separator vessels directly from the reactor, with
only a small amount of prior cooling. Hot vapor and liquid streams
are separated and cooled individually.
Another common process in some units is the use of a high-pressure
amine absorber to remove H2S from the recycle hydrogen stream.
Distillation systems can vary substantially in their flow design.
Some units have an H2S stripper column placed before the
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Hydroprocessing Units
fractionator. The differences in configuration, as they influence
corrosion, will be addressed later in this chapter.
7.2 Types of Corrosion Common in
Hydroprocessing Units
7.2.1 High-Temperature Hydrogen Attack
Because all hydroprocessing units involve the use of hot, highpressure hydrogen in the reactor systems, it is essential to use
construction materials that are resistant to hydrogen attack at the
operating conditions experienced by these units. Chromium and
molybdenum alloys can reduce the potential damage from hightemperature hydrogen attack due to their strong carbide-forming
qualities. (See Chapter 1 for more information).
Hydrogen in the presence of temperatures greater than 232°C
(450°F) with partial pressures greater than 7 kg/cm2 (100 psi) can
cause hydrogen attack of carbon and low-alloy steels. This results in
decarburization that weakens the metal. In addition, methane can
form at interstices and cause fissuring, blistering, or possible failure.
Within distillation systems, hydrogen attack is not a danger as the
hydrogen partial pressures are considerably lower.
API 941, “Steels for Hydrogen Service at Elevated Temperatures
and Pressures in Petroleum Refineries and Petrochemical Plants”
(Washington, DC: American Petroleum Institute, 1970), serves as a
guide to operating limits for steels in hydrogen service. This is
included as Appendix O. API 941 was originally developed by G.
A. Nelson and is commonly known as the Nelson Curves. The
curves are periodically updated as new data becomes available.
The axes are hydrogen partial pressure and operating temperature,
and the area below a given material’s curve is considered acceptable
operating conditions for that material. Common upgrades in
situations where carbon steel is not acceptable are 1-1/4 Cr-1/2 Mo
and 2-1/4 Cr-1 Mo alloys. Historically, many oil companies apply a
28C (50F) safety factor when using the Nelson Curves to select
materials, except for reactors. Material selection for reactors
typically incorporates a 14C (25F) safety factor since reactor
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temperature control is more closely monitored than temperature
control for other refinery equipment.
Hydrogen diffuses through overlays and attacks the underlying base
material so, regardless of the overlay material, the base material
should be selected to satisfy API 941 requirements.
7.2.2 High-Temperature H2S Corrosion – With
Hydrogen Present
Hydrotreater feedstocks typically contain sulfur compounds
(mercaptans, sulfides, disulfides, and thiophenes) which are
converted to hydrogen sulfide (H2S) under reactor conditions. (See
Chapter 7 for more information).
Areas of hydroprocessing units susceptible to high-temperature
hydrogen sulfide corrosion with hydrogen present (H2-H2S) are the:
·
Reactor feed downstream of the hydrogen mix point
·
Reactor
·
Reactor effluent
·
Recycle hydrogen gas.
These areas include the exchangers, heaters, separators, piping, etc.
that compose these systems.
H2S reacts with metals at high temperatures (288C [550F]).
The presence of hydrogen typically increases H2S corrosion rates on
carbon steel and low-alloy steels. A reasonably good estimate of
corrosion rates in H2-H2S systems can be made from data presented
in Figure 7.3, commonly known as the Couper-Gorman Curves.
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Figure 7.3 High-Temperature H2-H2S Corrosion of Carbon Steel
Under H2-H2S corrosive conditions, refiners have found that alloys
with up to 5% chromium (Cr) offer no significant improvement over
carbon steel. 9% Cr alloys provide only marginal improvements.
Both these alloys are considered ineffective in resisting corrosion.
12% Cr, on the other hand, is resistant to most H2S ranges, but
corrosion may still occur if the chromium content is on the low end
of the scale or if service conditions are severe. In addition, the 12%
Cr alloys are not commonly used due to fabrication difficulties and
the possibility of 885F embrittlement in service.
In cases where Cr-Mo alloys or 12% Cr alloys are predicted to have
moderate corrosion rates, the refiner may be economically justified
to upgrade the material to reduce fouling or plugging from corrosion
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products. Austenitic stainless steels (18% Cr) are usually required
to meet the corrosion and plugging-resistance requirements.
7.2.3 High-Temperature H2S Corrosion – With
Little or No Hydrogen Present
Another form of H2S corrosion can occur in feed systems upstream
of the hydrogen injection point and in some fractionator sections
after the hydrogen has been separated out. This occurs usually at
temperatures greater than 260°C (500°F). Usually, the hydrogen
partial pressures are less than 4 kg/cm2 (< 50 psi).
With this particular corrosion mechanism, an alloy’s corrosion
resistance is directly proportional to its chromium content. Alloys
with intermediate chromium provide better protection than carbon
steel. The usual upgrades used for temperatures above 260°C
(500°F) are 5 Cr, 9 Cr, 12 Cr, or 300 series stainless steels. Alloys of
12 Cr, such as type 405 and type 410S stainless steels, are typically
used only for thin components, such as cladding, trays, and tubing.
Thick sections of this grade are fairly difficult to fabricate.
Available published corrosion rate data is inadequate to address H2S
corrosion encountered in hydroprocessing unit fractionation
sections. However, the McConomy Curves are the most commonly
used published literature for feed areas upstream of the hydrogen
injection point. These curves were developed from crude unit and
hydroprocessing unit feed furnace tube field data and laboratory
tests. Due to criticism that these curves are too conservative for
some applications, a revised set of McConomy Curves reduced the
predicted corrosion rates by about 2.5. The revised curves are
commonly used for crude, coker, and FCC units and
hydroprocessing feed systems upstream of the hydrogen injection
point.
While the revised curves remain somewhat conservative for the
applications listed previously, they are inaccurate for predicting
corrosion rates for low-concentration, high-temperature H2S
corrosion found in some hydroprocessing unit fractionation
sections. One proposed reason for the inaccurate predictions is that
the data sources for these curves reflect a wide range of sulfur
species, with some corrosive and some not. However, the total
sulfur content in the hydroprocessing fractionator feed stream is
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almost entirely corrosive. Material selection for these areas is
primarily based on field experience with similar units.
7.2.4 Naphthenic Acid Corrosion
Naphthenic acid corrosion may be a problem in hot feed piping and
equipment, if the feed contains a high concentration of naphthenic
acids.
The naphthenic acid concentration in a feed is indicated by the total
acid neutralization number (TAN or neut. no.), which is determined
by using ASTM test methods D6641 or D974.2 It is important that
the H2S and mercaptans are removed from the feed prior to testing
for naphthenic acid.
Carbon steel, chrome-moly steels, and some 300 series stainless
steels can suffer accelerated corrosion at certain high-acid
concentrations (neut. no. > 1.5) and at temperatures greater than
232°C (>450°F). Upgrading to type 316L stainless steel or other
high-molybdenum alloys (>2% to 3% Mo) can help resist
naphthenic acid corrosion.
Most vulnerable to naphthenic acid attack are components upstream
of the hydrogen mix point, operating at temperatures in the range of
232°C to 288°C (450°F to 550°F). Areas with turbulence or high
velocity are particularly susceptible. No problems have been
reported downstream of the hydrogen mix point, in reactor feed
piping, heater tubes, and exchanger tubes. Pilot plant data has
shown that a significant portion of naphthenic acid content is
destroyed in the first reactor. Therefore, no special material
considerations are required to address this corrosion problem
downstream of this reactor.
7.2.5 Ammonium Bisulfide Corrosion
Ammonium bisulfide (NH4HS) is the product of ammonia (NH3)
and hydrogen sulfide (H2S) gases. As the reactor effluent stream
cools down, solid NH4HS can crystallize out of the vapor phase,
plugging up exchanger tubes and causing underdeposit corrosion.
Water is commonly injected ahead of effluent air coolers to dissolve
ammonium bisulfide, preventing these deposits.
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Unfortunately, ammonium bisulfide solutions are highly corrosive,
leading to rapid attack of carbon steel tubes. The presence of small
quantities of cyanides, oxygen, or ammonium chloride in the
process fluids can further accelerate the corrosion.
In the construction of new units, some refiners use the Kp factor
(developed by R.L. Piehl) in selecting materials. The Kp factor is
the mole percent of ammonia (NH3) times the mole percent of
hydrogen sulfide (H2S) in the dry stream entering the reactor
effluent coolers. This factor determines the need to alloy air coolers.
Corrosion rates for ammonium bisulfide increase in relation to its
concentration. The recommended concentration limit for separator
water falls in the range of 2% to 10%. Sometimes adjusting the
water injection rate can control the NH4HS concentration level.
Optimum water injection rates are one key to controlling
ammonium bisulfide corrosion. The water rate should be high
enough so that 25% or more remains unvaporized. In addition, the
NH4HS content should be within desired limits, and the process
velocity should be within specified limits.
NH4HS corrosion is velocity sensitive. Severe corrosion/erosion of
carbon steel tubing is likely to occur at tube velocities greater than 6
m/s (20 ft/s) unless the process fluid is very low in ammonia and
hydrogen sulfide. Therefore, velocities should remain within the 6
m/s (20 ft/s) maximum for air coolers with carbon steel tubes.
Stainless steel ferrules, with tapered ends, may be used at both inlet
and outlet tube ends. The upper velocity limit can be raised to 9 m/s
(30 ft/s) for alloy tubing.
Another factor in ammonium bisulfide corrosion is the presence of
oxygen, which can lead to rapid corrosion or fouling. Injection
water should be free of oxygen, measuring less than 15 ppb to 50
ppb. Any oxygen contamination problems, including periodic
spikes, can be detected by frequent testing of the injection water.
Oxygen contamination can also be detected by analysis of corrosion
products in the exchanger.
Typically, many corrosion factors are interrelated. One factor may
be allowed to exceed recommended levels if all the others are under
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control. However, oxygen contamination is one factor that alone can
immediately lead to severe corrosion.
Good flow distribution of vapor, liquid hydrocarbon, and water
phases is essential for corrosion prevention. Good flow distribution
can be enhanced by:
•
A balanced design for inlet and outlet headers
•
Keeping fluid velocities high enough to minimize phase separation.
Phase separation and risks of deposits and underdeposit corrosion
occur when velocity is 3 m/s (10 ft/s) in the air cooler.
Fouling deposits in the cooler may disrupt flow and lead to
corrosion. Good water distribution minimizes accumulation of
fouling deposits in the cooler. Therefore, many units have injection
points on the inlets to each bank.
Process unit equipment can be designed to prevent ammonium
bisulfide corrosion. For example:
•
Place header boxes at both ends of air-cooled exchangers
•
Locate header boxes in a way that facilitates tube cleaning
•
Avoid the use of U-bends because they are susceptible to
erosion-corrosion.
7.2.6 Chloride Stress Corrosion Cracking
(SCC)
Chloride stress corrosion cracking (SCC) of austenitic steels can
happen when the following conditions are present:
•
Liquid water temperature 60°C (140°F)
•
Chlorides, especially when concentrated
•
Tensile stresses.
Chlorides may be present in the plant feed and/or the makeup
hydrogen when the hydrogen source is a catalytic reformer unit.
This causes ammonium chloride deposits in heat exchangers
downstream of the reactor.
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Austenitic 300 series stainless steels, in this environment, are
acceptable for feed/effluent exchangers. These exchangers are too
hot for large amounts of salt to form, and any salts that do
accumulate will be dry. In colder exchangers, the 300 series
stainless steels are not recommended due to the risk of chloride
SCC.
7.2.6.1 Failures Often Happen After Startup
Many refineries have experienced chloride SCC in stainless steel
drain lines that branch off from stainless steel piping in the reactor
feed and effluent systems. These failures generally occur shortly
after startup following a turnaround.
Water with chlorides can accumulate in the lines during shutdown
washing steps or when the piping is exposed to the atmosphere. On
startup, when the temperature in the branches exceeds 60°C
(140°F), SCC begins to occur. At this temperature, the trapped water
begins to boil off, and the chlorides become both concentrated and
hot.
Failures generally happen at predictable points. Cracks and leaks
most often occur at nonstress-relieved welds. These sites are prone
to high residual stresses and, therefore, many refiners are stress
relieving these drain lines or upgrading them to alloy 20 or alloy
825. However, cracking can occur in any highly stressed area, such
as nozzle areas affected by flange rotation.
7.2.6.2 Additional Considerations with Stainless
Steel
Some isolated cases have been reported of chloride SCC problems
in the stainless steel feed and effluent piping. For example, chloride
cracking has been reported in the ring grooves of flange faces.
Another risk of SCC exists in reactor effluent/stripper feed
exchangers, when stainless steel (austenitic and duplex) is used for
tubing. Hydrocarbon liquid from the separator, i.e., stripper feed,
may contain small amounts of water with dissolved chloride salts.
When the hydrocarbon is reheated, the water vaporizes, and the
remaining salt deposits may cause rapid chloride cracking or pitting
in the tubing.
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Feed heaters, especially those with vertical stainless steel tubes, are
sometimes exposed to shutdown conditions capable of causing
chloride SCC. If pools of water remain in the tubes after a water
wash, chlorides in the water will concentrate when the furnace is
fired. Water must be removed from the tubes before startup by
airblowing or, for vertically tubed furnaces, by oil circulation.
Stainless-clad reactors can experience chloride SCC if they are
water-flooded during a catalyst removal process. Preventive
measures are:
•
Avoiding water boiling
•
Using condensate or fresh water with chloride content under 50
ppm during the catalyst removal.
7.2.7 Polythionic Acid (PTA) Stress Corrosion
Cracking
Polythionic acid SCC occurs only on austenitic stainless steels and a
few related austenitic alloys, such as alloy 800. The cracking occurs
when these alloys have become sensitized by welding, postweld
heat treatment, or exposure to temperatures over 371°C to 454°C
(700°F to 850°F). Polythionic acid forms from the reaction of iron
sulfide scales with oxygen and moisture. As a result, this type of
SCC occurs during shutdowns when equipment is exposed to air and
moisture.
7.2.7.1 Stainless Steels Used to Prevent PTA
Various stainless steels can be used to prevent PTA stress corrosion
cracking. They are listed, below, with recommended limits to avoid
sensitization.
•
Type 304 or type 316—Used only for parts which are not welded
or heat-treated and have operating and regeneration temperatures
less than 371°C to 399°C (700°F to 750°F).
•
Type 304L or type 316L—Used on welded or heat-treated parts,
with maximum operating temperatures up to 371°C to 399°C
(700°F to 750°F).
•
Type 321—Acceptable for welded or heat-treated parts, with
maximum operating temperatures up to 416°C (780°F).
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•
Type 347—Acceptable for welded or heat-treated parts with
maximum operating temperatures of 454°C (850°F).
•
HF Modified—Once considered immune to PTA SCC and used
with piping at maximum operating temperatures of up to 454°C
(850°F). In recent years, some incidences of cracking have been
reported after exposure to operating conditions below 371°C
(700°F).
7.2.7.2 Other Methods to Prevent PTA SCC
Other methods used to mitigate PTA SCC involve minimizing the
formation of polythionic acids. These include:
•
Nitrogen blanketing the equipment and piping during turnarounds to prevent exposure to air and moisture
•
Keeping the metal above the dew point
•
Washing with soda ash solutions.
Soda ash wash produces a residual alkaline film on the metal, which
neutralizes acid buildup. Appendix P, NACE RP0170 (current
edition), “Protection of Austenitic Stainless Steels and Other
Austenitic Alloys from Polythionic Acid Stress Corrosion Cracking
During Shutdown of Refinery Equipment” (Houston, TX., NACE),
provides procedures for washing with soda ash solutions.
7.2.8 Wet H2S Cracking
Wet hydrogen sulfide cracking can occur within hydroprocessing
units in a variety of forms, such as:
•
Sulfide stress cracking (SCC)
•
Hydrogen-induced cracking (HIC)
•
Stress-oriented hydrogen induced cracking (SOHIC).
These types of cracking happen when steel is exposed to liquid
water with about 50 ppm H2S or greater. The cracking usually
follows wet H2S corrosion which generates hydrogen (Fe + H2S Õ
FeS + 2H). The hydrogen can charge into the metal. As mentioned
previously, free cyanide can increase the severity of the hydrogen
charging by stripping off any protective FeS scales that may be
forming.
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7.2.9 Sulfide Stress Cracking (SSC)
Sulfide stress cracking (SSC) happens mainly with high-strength
ferritic or martensitic steels. The cracking generally occurs in steels
above about 621 N/mm2 (90,000 psi) in yield strength, or above
Rockwell C (Rc) 20 to 22 in hardness. The problem can happen
when liquid water and hydrogen sulfide are present, but even a thin
film of condensed moisture provides enough water to lead to
cracking.
The failures of valve stems and valve trim are the most commonly
encountered sulfide cracking problems in hydrotreaters. Trim
material fabricated out of the common 400 series stainless steels
(12% Cr to 13% Cr) are particularly prone to failure.
Sulfide cracking at these sites most often happens in the reactor
effluent system, including the area of effluent air coolers and
separators, after it has cooled sufficiently for liquid water to form.
SSC has also been reported in the recycle hydrogen system and in
some distillation overhead systems.
Since austenitic stainless steels are essentially immune to SSC, the
common solution to sulfide cracking of valve trim is to use an 18
Cr-8 Ni stainless steel. Other options include the use of:
•
12 Cr trim which has been certified as meeting NACE MR0175,
(current edition) “Sulfide Stress Cracking Resistant Metallic
Materials for Oilfield Equipment” (Houston, TX., NACE).
NACE MR0175 is found in Appendix T.
•
Hard-facing alloy valve trim for pressure let-down valves, particularly in wet H2S services
•
ASTM A6383 grade 660 precipitation-hardened stainless steel
for valve stems. Grade 660 should have a maximum hardness of
35 Rc.
Commonly used rotor materials in centrifugal recycle gas
compressors, such as 4330 steel and 4140 steel, can be highly
susceptible to SSC. As a result, compressors for hydrotreater recycle
hydrogen service are required to be constructed of alloys with less
than 621 N/mm2 (< 90,000 psi) yield strength and <22 Rc hardness.
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Hard weldments are also susceptible to SSC and should be avoided
by using good fabrication practices cited in NACE SP0472 (current
edition), “Methods and Controls to Prevent In-Service
Environmental Cracking of Carbon Steel Weldments in Corrosive
Petroleum Refining Environments” (Houston, TX., NACE). This
guide, found in Appendix G, should be followed to limit hardness of
both weld deposits and heat-affected zones (HAZs) for most wet,
sour services. Procedures used for welding carbon steel should
ensure that the 200 HB weld hardness limit is not exceeded. A
maximum allowable weld hardness of 225 HB is recommended for
low-alloy steels.
7.2.10 Hydrogen Induced Cracking (HIC) and
Stress-Oriented Hydrogen Induced
Cracking (SOHIC)
As mentioned previously, these two corrosion forms result when
hydrogen is charged into the steel from corrosion in wet H2S
environments. Atomic hydrogen collects at subsurface laminations,
particularly at non-metallic inclusions, and reacts to form molecular
hydrogen, causing internal blistering and cracking. Molecular
hydrogen is unable to diffuse back into the metal structure and
remains trapped in the blisters.
Dirtier steels (with a high sulfur content) are more prone to HIC and
SOHIC, since they have more non-metallic inclusions. HIC and
SOHIC, unlike SSC, can also occur in a variety of soft materials.
There is not a single, well-defined method for preventing HIC or
SOHIC. However, SOHIC does appear to be significantly reduced
when vessels have received postweld heat treatment (PWHT).
Because PWHT nearly eliminates risks for SSC, most refiners now
specify PWHT for equipment in H2S service. Using 100% wet
fluorescent magnetic particle testing (WFMT) after PWHT is also
common. SOHIC has not been reported with the use of seamless,
ASTM A1064 grade B piping, except under extremely severe
conditions. As a result, many refiners do not require PWHT for this
product.
A number of low-impurity, HIC-resistant steels have recently
become available. They are costly and many have not performed at
expected levels of success. Most refiners are currently using these
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steels only for critical pieces of equipment in the most severe
service areas, i.e., for headers in effluent air coolers and for
separators.
Coatings have been tried with mixed success throughout the
industry. Cladding with stainless steel, such as type 304L or type
316L, is the most reliable way of avoiding wet H2S cracking. This
product, too, is expensive. The base metal under the cladding
typically has no added requirements, and PWHT is not required for
a fully clad vessel unless required by Code.
7.3 Material Property Degradation
Mechanisms
Material property degradation mechanisms common to
hydroprocessing units include temper embrittlement and hydrogen
embrittlement.
7.3.1 Temper Embrittlement
Many hydrotreating reactors that operate above 360°C (680°F) endof-run temperatures may suffer temper embrittlement in service.
(See Chapter 1 for more information).
Temper embrittlement of chrome-moly steels, particularly 2-1/4 Cr1 Mo steel, occurs when the steel is heated for a long time in the
360C to 566C (680F to 1050F) range. Generally, embrittlement
involves the gradual accumulation of tramp elements, such as
antimony, tin, arsenic, and phosphorus, in the grain boundaries of
the steel. With embrittlement, a significant rise in the steel’s ductileto-brittle transition temperature occurs. The ductile-to-brittle
transition temperature is the temperature below which cracks may
propagate in an instantaneous catastrophic manner and above which
cracks will be arrested by the basic toughness of the material.
To avoid the sudden brittle fracture of a reactor operating in the
embrittlement temperature range, the accepted procedure is to
maintain low pressure in the reactor when below the ductile-tobrittle transition temperature. Low pressure is generally defined as
less than 25% of the reactor’s design pressure. Brittle fracture is
considered unlikely if the stress level can be kept to less than 20% of
the material’s yield strength.
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Every reactor will be affected by a variety of unique factors, and
remedies must be considered individually. Current practice in the
construction of new reactors is to require ultra-clean steels and to
carefully screen the materials being used to minimize temper
embrittlement. Keeping to the pressure restrictions and maintaining
minimum pressuring temperatures (MPTs) are essential elements in
preventing failures due to temper embrittlement in hydrotreating
reactors.
7.3.2 Hydrogen Embrittlement
Hydrogen embrittlement is often a concern in the reactors of
hydroprocessing units, due to the large concentrations of dissolved
hydrogen that can build up within the walls of a unit operating at the
required high temperatures and hydrogen partial pressures.
If the reactor walls are thick enough and are cooled rapidly when
shutting down, the dissolved hydrogen has no opportunity to escape
from the metal during cooling. If significant amounts of the
dissolved hydrogen remain in the steel after cooling, mechanical
properties may be temporarily affected. The degradation in
mechanical properties is called hydrogen embrittlement.
The condition exists only while the hydrogen remains in the steel,
and the steel will regain its original properties if the hydrogen is
allowed to escape. Even though hydrogen may be present in the
metal, the condition known as hydrogen embrittlement occurs only
at temperatures below about 149°C (300°F).
Special cooling procedures are often required when removing
reactors from service in order to let a significant amount of the
hydrogen diffuse out of the metal before the reactor is cooled below
149C (300F). Cooling rates of 28°C/hr to 56°C/hr (50°F/hr to
100°F/hr) are considered adequate to provide enough time for
degassing.
Heavy-walled reactors in hydrogen service are especially vulnerable
and should be inspected with particular care both after initial
construction and during any plant turnarounds to guard against
existing defects that might enlarge due to hydrogen embrittlement.
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7.4 Selection of Materials
Material selection is influenced by the equipment or piping location
within a hydroprocessor unit.
7.4.1 Reactor Loop – General
The materials of construction used in reactor loops of a hydrotreater,
single-stage hydrocracker or the first stage of a two-stage unit must
be resistant to the following forms of corrosion:
•
High-temperature hydrogen attack
•
High-temperature hydrogen sulfide corrosion
•
Aqueous corrosion by ammonium bisulfide
•
Stress corrosion cracking by chlorides, sulfur acids, or sulfides
•
Naphthenic acid corrosion (at high concentrations).
7.4.2 Reactor Feed System
Up to the point of recycle hydrogen addition, the reactor feed
system can be vulnerable to corrosion if the feed contains hydrogen
sulfide (H2S) at temperatures over 260°C (>500°F) or naphthenic
acid at temperatures exceeding 232°C (>450°F).
H2S corrosion can be minimized by using alloys containing 5%
chrome or better. Naphthenic acids may necessitate the use of type
316 or type 316L stainless steel.
After the point of recycle hydrogen addition, progressively higher
alloys are required to resist both hydrogen attack and hightemperature H2-H2S corrosion. In most plants, threshold
temperature for H2-H2S corrosion is 260°C (500°F), but depends on
the amount of H2S introduced with the recycle gas.
Austenitic steels are usually used for piping and exchangers in
environments where the temperature exceeds 260°C (500°F). Hot
piping is commonly constructed of type 321 stainless steel, since
type 347 piping is more costly and generally more difficult to weld.
Exchanger bundles are usually type 321 stainless steel, while shells
and channel sections are clad with type 321 or type 347 stainless
steel. For cladding thick-walled components, type 347 stainless steel
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is preferred; type 321 has been known to sensitize during lengthy
fabrication heat treatment.
Hydrogen attack becomes a significant materials consideration in
the reactor feed system at temperatures above 232°C (450°F).
Above this temperature threshold, carbon steel cannot be used even
as a base metal on stainless steel clad components. Although
stainless steels are immune to hydrogen attack under plant
conditions, hydrogen can diffuse through stainless cladding to attack
the base metal.
Within a relatively narrow temperature span of 232°C to 260°C288°C (450°F to 500°F-550°F), 1-1/4 Cr-1/2 Mo or 2-1/4 Cr-1 Mo
may be used to resist hydrogen attack. Above 260°C to 288°C
(500°F to 550°F), piping will generally be type 321 steel. Exchanger
channel sections and shells will be stainless clad, with 1-1/4 Cr-1/2
Mo or 2-1/4 Cr-1 Mo base metal used as needed to protect against
hydrogen attack.
Corrosion products may plug catalyst and downflow reactors and
reduce run lengths, providing economic justification for upgrading
alloys in feed exchangers, piping, and furnace tubes. Corrosion rates
low enough to be acceptable from a thickness-loss consideration can
lead to the production of large amounts of corrosion products.
7.4.2.1 Reactor Feed Furnaces
Tubes and return bends are commonly constructed of type 347
stainless steel, although type 321 has also been used. Return bends
should be wrought rather than cast, both to obtain superior quality
and because castings tend to develop sigma embrittlement above
temperatures of 538°C (1000°F).
7.4.2.2 Reactors
Reactors are constructed of low-alloy steel for protection against
hydrogen attack and are protected from H2-H2S corrosion by
austenitic stainless steel roll-bond cladding or weld overlays. The
most common base metal for reactors is 2-1/4 Cr-1 Mo steel,
although 3 Cr-1 Mo has also been used. Alloys lower than 2-1/4 Cr1 Mo are occasionally used, when temperature and hydrogen partial
pressure permit.
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Reactor internals are constructed of austenitic stainless steel (type
321 or type 347), with aluminum diffusion coating (aluminizing)
sometimes specified for catalyst support screens to help prevent
corrosion that may result in plugging from scales. Aluminizing is
essentially immune to H2S corrosion.
7.4.3 Reactor Effluent System
In the reactor effluent system, from the reactor to the reactor
effluent/stripper feed exchanger, materials are selected by the same
criteria as in the reactor feed system. Stainless steels should be used
for corrosion protection until the feedstock can be cooled below the
threshold for high-temperature H2-H2S corrosion, which is about
260°C (500°F).
Alloys resistant to hydrogen attack must be used for temperatures
down to about 232°C (450°F). The exact threshold temperatures for
H2-H2S corrosion and hydrogen attack can vary somewhat, related
to the partial pressures of H2S and hydrogen. On surfaces, such as
exchanger tubes and tube sheets that are subject to two-sided attack,
the conditions existing on both sides must be considered.
From the reactor outlet temperature down to about 260°C (500°F),
piping and exchanger bundles are usually type 321 steel, and
exchanger shells are either type 321-clad or type 347-clad. Base
metals used for exchanger shells may again be 2-1/4 Cr-1 Mo or 11/4 Cr-1/2 Mo, depending on the alloy content needed to provide
adequate resistance to hydrogen attack. Below temperatures of
232°C (450°F), the hydrogen attack threshold, carbon steel is
generally used.
7.4.4 Reactor Effluent – Distillation Feed
Exchangers
Many plants use an exchanger that cools the reactor effluent stream
by exchanging it with the separator liquid on its way to the first
distillation column after the reactor system. These exchangers pose
special corrosion problems, such as entrainment of small quantities
of salt-containing water in the separator liquid. Salt deposits are left
on the tubes as the stock is heated and the water evaporates, and
may lead to corrosion of carbon steel tubes.
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Tube life is highly variable, depending on temperature and the
amount of salt entrained into the exchanger. Chrome-moly steels
generally perform no better than carbon steel under these
conditions. Austenitic steels are prone to failure from chloride SCC
or underdeposit ammonium chloride pitting and generally should
not be used.
Tubes in these exchangers are usually either carbon steel or very
expensive alloys, such as alloy 825, 6 moly austenitic stainless steel,
or alloy 625. New plant construction generally specifies carbon
steel, but when reactor effluent-side temperatures are high enough to
cause high-temperature H2S corrosion, an alloy with very high
resistance to chloride corrosion and SCC is required.
7.4.5 Effluent Air Coolers
Effluent air coolers are probably the piece of equipment most
vulnerable to ammonium bisulfide (NH4HS) corrosion. Most plants
initially install carbon steel tubes for effluent air coolers, but some
units with high Kp values have installed duplex stainless steel, alloy
800, or alloy 825.
In other situations, carbon steel has experienced corrosion failures
due to excessive velocities, oxygen in the injection water, poor
distribution of flow, or other causes. Where such problems have
occurred and tube materials were upgraded, the product was
probably alloy 400, alloy 800, or alloy 825.
The alloy 800 series is resistant to ammonium bisulfide, but can be
prone to polythionic SCC. Alloy 825 contains molybdenum and is
stabilized, which gives it superior resistance to polythionic or
chloride SCC as well as ammonium bisulfide corrosion.
Duplex stainless steels, such as type 2205, are increasingly used for
tubes and header boxes, but special requirements should be imposed
on the materials as well as the fabrication and welding practices.
Welds or HAZs that do not have the proper ratio of austenite/ferrite
in their microstructure can be susceptible to hydrogen embrittlement
and SSC.
Although they offer good resistance to NH4HS corrosion, austenitic
stainless steel tubes are seldom used in this service since they are
susceptible to chloride SCC. Type 410 and type 430 stainless steel
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tubes used in effluent air coolers have also experienced failures
from isolated pitting. Alloy 400 has been used successfully in a few
air coolers, but may not be suitable for units with high levels of
NH4HS.
Stainless steel ferrules installed at both inlet and outlet ends of the
steel tubes in effluent air coolers provide increased protection
against tube end erosion/corrosion. When ferrules are used, the ends
should be tapered to ensure smooth flow transition.
Carbon steel header boxes are prone to corrosion if velocities or
turbulence are excessive. Industry experience has shown that tube
corrosion is generally accompanied by attacks on header boxes as
well. For this reason, alloy header boxes are recommended with
alloy tubes.
In addition to NH4HS corrosion, failures can result from NH4Cl
corrosion. Units with two air coolers in series, with water injection
downstream of the first air cooler, may experience NH4Cl deposits
and pitting at the outlet ends of the first air cooler. No practical
materials can prevent NH4Cl corrosion, but raising the process
temperature can usually prevent it.
7.4.6 Effluent Air Cooler Inlet and Outlet
Piping
Piping upstream (from the water injection point) and downstream of
the effluent air cooler is prone to the same NH4HS corrosion as the
air cooler, with corrosion typified by highly localized metal loss at
bends, tees, and other points of local turbulence. Such corrosion is
most likely to occur at high NH4HS concentration levels and where
fluid velocities are high. Carbon steel piping for this use should be
designed with a 6 m/s (20 ft/s) maximum limit.
Alloy 800, alloy 825, type 316L stainless steel (for applications
below 60C [140F]), alloy 20, and alloy 2205 have been used in the
following situations:
•
New units predicted to be extremely corrosive
•
When high reliability is desired
•
When periodic rigorous inspection may be difficult or uneconomical
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When corrosion occurs in existing plants.
Alloy 800 may experience SCC failures when it is supplied with a
high-carbon content or large grain size.
When carbon steel is used, it has a high corrosion allowance of 6.4
mm (1/4 in.). Balanced inlet and outlet piping is also usually
specified.
Wet, sour process fluids present in many plants downstream of the
effluent air cooler can cause rapid SSC of high-strength steels. In
new plant construction, therefore, 18 Cr-8 Mo stainless steel trim is
specified for services where SSC appears likely.
7.4.7 Separator Vessels
Separator vessels normally have very low corrosion rates, except for
units operating with greater than ten percent (10%) NH4HS. The
major issue with these vessels is that incoming process fluid may
impinge on the shell or heads, causing localized NH4HS corrosion
at that point. Installation of a stainless steel impingement baffle or
wear plate to shield the entire impingement area usually can prevent
this problem.
One major exception is the hot separator in a hydrotreater design
where the first separator operates at or near the full reactor outlet
temperature. In this instance, stainless-clad construction is
recommended to protect against high temperature H2-H2S corrosion
in the hot separator. Base metal is typically 2-1/4 Cr-1 Mo or 1-1/4
Cr-1/2 Mo steel.
Cold separators containing sour water have been built of HICresistant steel or entirely clad with a 300 series stainless steel to
prevent HIC or SOHIC.
7.4.8 Recycle Hydrogen System
Significant corrosion seldom occurs in the recycle hydrogen system.
However, the recycle gas compressor, which usually contains
materials such as 4330 steel or 4140 steel, may experience SSC. To
avoid SSC, the strength and hardness of compressor materials can
be limited.
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To mitigate SSC and NH4HS erosion-corrosion, the compressor
must be kept dry by maintaining the mist eliminator in the
compressor knockout drum in good condition. Steam-tracing the
compressor suction line from the knockout drum also keeps the
compressor dry.
Valve trim is typically 18 Cr-8 Mo stainless steel.
7.4.9 Distillation Section
Construction materials in the distillation section are based on the
need to resist high-temperature H2S corrosion. Depending on H2S
concentration, if H2S is present at temperatures above 260°C to
316°C (500°F to 600°F), alloy is required. Where H2S is absent or
temperatures are below 260°C (500°F), carbon steel is generally
sufficient. Distillation systems vary widely, so each unit must be
reviewed on a case-by-case basis.
In the bottom half of many fractionator columns and the fractionator
column reboiler, corrosion of carbon steel is often minimal despite
high temperatures because H2S has been stripped out of the
hydrocarbon. If the H2S content exceeds 1 ppm and temperatures
are above 316C (600F), corrosion of carbon steel may occur in the
bottom of the fractionator column, the reboiler, the bottoms line to
the splitter, and the flash zone of the splitter column. Corrosion in
the bottom of the splitter column or in its reboiler is unlikely since
H2S should be stripped out.
Overhead condensers and drums exposed to both water and H2S
may show moderate corrosion that may be controlled by a filmingamine inhibitor injection. If there is excessive water carryover from
the reactor separator into the distillation section feed, ammonia and
chlorides can be present in the column overheads. These produce
NH4HS and NH4Cl corrosion. In the overhead systems, some
refiners apply materials and fabrication controls to minimize wet
H2S cracking. As a rule, however, HIC-resistant steels are not
typically used in the overhead of the distillation column.
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7.5 Optional Team Exercise
Three examples of typical distillation systems found in
hydroprocessing units are provided below. Once your instructor
assigns your team one of these systems, decide whether H2S
corrosion would be a problem in this system and, if so, determine
materials and/or steps that you would take to prevent this type of
corrosion.
System 1
A typical H2S stripper column, which removes hydrogen sulfide
from first-stage product prior to forwarding to the second stage.
Temperatures in the H2S stripper column are below 260C (500F).
System 2
Feed to the distillation section contains large amounts of H2S since
it consists of first- and second-stage product. Outlet temperature on
the main fractionator column feed heater is 232C (450F).
System 3
A new plant is being designed in which feed to the distillation
section is a combination of first- and second-stage product. The
transfer line temperature is specified at 316C (600F), but could
possibly rise well over the temperature specification.
System Assigned by Instructor________
H2S Corrosion a Problem____Yes____No
Materials/Steps for Prevention
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References
1. ASTM D664, “Standard Test Method for Acid Number of
Petroleum Products by Potentiometric Titration” (West
Conshohocken, PA: ASTM, 1995).
2. ASTM D974, “Standard Test Method for Acid and Base
Number by Color-Indicator Titration” (West Conshohocken,
PA: ASTM, 1997).
3. ASTM A638/A638M, “Standard Specification for Precipitation Hardening Iron Base Superalloy Bars, Forgings, and
Forging Stock for High-Temperature Service” (West Conshohocken, PA: ASTM, 1995).
4. ASTM A106, “Standard Specification for Seamless Carbon
Steel Pipe for High-Temperature Service” (West Conshohocken, PA: ASTM, 1999).
5. “Process Industries Corrosion—The Theory and the Practice”
by J. Gutzeit (Houston, TX: NACE International, 1986).
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Chapter 8:Catalytic Reforming Units
Objectives
Upon completing of this chapter, you will be able to do the
following:
•
Identify the purpose of a catalytic reforming unit
•
Differentiate between Motor Octane Number (MON) and
Research Octane Number (RON)
•
Describe the characteristics of the preferred feedstock for catalytic reformers and identify the feed components
•
Identify and discuss the reactions taking place in catalytic
reformers and the products formed
•
Discuss the composition of the reforming catalyst, its role in the
catalytic reforming process, and catalyst regeneration
•
Discuss the significance of hydrogen in the catalytic reforming
process
•
Discuss feed pretreatment and its importance to catalytic
reforming
•
Identify categories of catalytic reforming processes used in
refineries today
•
Identify the equipment and describe the process flow in a
catalytic reforming unit
•
Differentiate between cold shell and hot shell reactor design
•
Identify the types of corrosion and materials problems common
in catalytic reforming units
•
Discuss the effect of temperature, pressure, and stream composition on corrosion in catalytic reforming units
•
Identify materials of construction preferred for equipment and
piping in catalytic reforming units
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Catalytic Reforming Units
•
Identify and discuss corrosion control measures used in catalytic
reforming units
•
Describe the corrosion monitoring process in catalytic reforming
units
•
Identify inspection techniques used in catalytic reforming units.
8.1 Introduction
Since World War II, motor gasoline has been the principal product
of refineries. Starting in the 1960s, gasoline production became the
largest of any of the basic industries in the United States. During
1962, the 204 million tons of gasoline produced exceeded the output
of steel, lumber, and other high-volume products. Of this quantity,
over 90% was used in passenger cars and trucks.
Paralleling the growth in quantity, quality of motor fuel had to be
increased to keep up with engine development. Higher engine
speeds and higher compression ratios required higher octane fuels to
prevent detonation. In addition, emphasis on pollution abatement
required restriction or prohibition of the use of anti-knock
inhibitors, such as tetraethyl lead. As a consequence, the refining
industry developed processes to increase the natural anti-knock
characteristics of the gasoline.
The widely recognized measure of anti-knock characteristic of
motor fuels is octane number. Two standards exist, which are:
•
Motor Octane Number (MON)
•
Research Octane Number (RON).
MON is more indicative of high-speed performance. RON is more
indicative of normal driving performance and is less severe. Octane
ratings cited here are research octane numbers.
The demand for higher octane number motor fuel has stimulated the
use of catalytic reforming. The feedstock for this process is heavy
straight run gasolines and naphthas boiling in the range 180F to
375ºF (82C to 191C). Processing of light straight run gasolines
and naphthas (C5 to 180ºF [82C]) is not economical because the
yield is largely composed of butane and lighter hydrocarbons.
Heavier hydrocarbons (boiling above 400ºF [204C]) are not used
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as reformer feed because they are more easily hydrocracked,
resulting in excessive carbon laydown on the catalyst.
Typical analyses of feed and product for catalytic reformers are
shown in Table 8.
Table 8.1: Volume % of Feed and Product Components
COMPONENT
FEED
PRODUCT
Paraffins
Olefins
Naphthenes
Aromatics
45-55
0-2
30-40
5-10
30-50
0
5-10
45-60
In catalytic reforming, the following reactions occur:
•
Paraffins are isomerized and to some extent converted to naphthenes. The naphthenes are subsequently converted to aromatics.
•
Olefins are saturated to paraffins; the paraffins then undergo the
reactions in 1 above.
•
Naphthenes are converted to aromatics.
•
Aromatics are left essentially unchanged.
These conversions occur as a result of a series of complex reactions
as listed below:
•
1. Dehydrogenation of naphthenes to aromatics.
•
2. Dehydrocyclization of paraffins to aromatics.
•
3. Isomerization of normal paraffins to isoparaffins.
•
4. Hydrocracking of normal paraffins to isoparaffins.
In reactions 3 and 4 above, some of the isoparaffins are then
converted to aromatics.
8.1.1 Octane Number (RON)
Table 8.2, which is a listing of the RON of some pure hydrocarbons,
provides a general idea of the increase in octane numbers resulting
from the catalytic reforming process.
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Table 8.2: RON of Several Hydrocarbon Compounds
HYDROCARBON
NORMAL PARAFFINS:
Pentane
Hexane
Heptane
Octane
Nonane
ISOPARAFFINS:
Isopentane
Isoheptane
Isooctane
AROMATICS:
Benzene
Toluene
RON
61.7
24.8
0
-19.0
-17.0
92.3
42.4
100.0
130(±)
120.1
The overall result of catalytic reforming is to increase the octane
rating of the gasoline product substantially by increasing the
aromatic and isomer content.
8.1.2 Catalyst
All reforming catalysts in general contain platinum supported on a
silica or silica-alumina base. Platinum is thought to serve as a
promoter for hydrogenation and dehydrogenation reactions. The
base is chlorinated by loading with 1% chloride. During operation,
small amounts of water and chlorine are injected into the feed to the
first reactor. This promotes the isomerization, cyclization, and
hydrocracking reactions.
During operation, catalyst activity is reduced by carbon deposition
and chloride loss. Catalyst activity is restored periodically by hightemperature oxidation of the carbon followed by chlorination.
Depending on feed composition and operating conditions, runs of 6
months to 24 months between regenerations are realized. Generally,
the catalyst can be regenerated at least three times before it has to be
replaced.
The action of the catalyst requires the presence of hydrogen. Some
of the reactions produce an excess of hydrogen while others
consume hydrogen. The presence of hydrogen is assured by
recirculation with net production of hydrogen drawn off for use in
other processes requiring hydrogen or for use as fuel. The presence
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of excess hydrogen also retards the formation of carbon on the
catalyst bed.
The most important agent in catalytic reforming catalysts is
platinum. The feed contains certain metals, hydrogen sulfide,
ammonia, and organic nitrogen and sulfur compounds. All of these
materials tend to deactivate the catalyst. As a consequence,
pretreating of the feed is required.
Hydrotreating is usually employed for pretreatment. The feed is
passed through a reactor charged with a cobalt-molybdenum
catalyst. The action of this catalyst converts the organic sulfur and
nitrogen compounds to hydrogen sulfide and ammonia. These two
materials are then partially removed from the system with the net
production of hydrogen. The metals in the feed are retained on the
catalyst bed.
8.2
Catalytic Reforming
Processes
There are several major reforming processes in use today, which are
listed below:
Platforming
Powerforming
Ultraforming
Houdriforming
Iso-Plus Houdriforming
Catalytic Reforming
Rheniforming
UOP
Exxon
Standard Oil Indiana
Houdry
Houdry
Engelhard
Chevron
Reforming processes are classified as continuous, semiregenerative, or cyclic depending on the frequency of catalyst
regeneration. The equipment for the continuous process is designed
to permit the removal and replacement of catalyst during normal
operation. As a result, the catalyst can be regenerated continuously
and maintained at a high activity. As coke laydown and
thermodynamic equilibrium yields of reformate are both favored by
low-pressure operation, the ability to maintain high catalyst
performance by continuous catalyst regeneration is the major
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advantage of the continuous type of unit. This advantage has to be
evaluated with respect to the higher capital costs and possible lower
operating costs due to lower hydrogen recycle rates and pressures
needed to keep coke laydown at an acceptable level.
The semi-regenerative unit is at the other end of the spectrum,
having the advantage of minimum capital costs. Regeneration
requires the unit to be taken off-stream. Depending upon severity of
operation, regeneration is required at intervals of 3 months to 24
months. High hydrogen recycle rates and operating pressures are
utilized to minimize coke laydown and consequent loss of catalyst
activity.
The cyclic process is a compromise between the above extremes and
is characterized by having a swing reactor in addition to those onstream. When catalyst activity in one of the on-stream reactors
drops below the desired level, that reactor is replaced by the swing
reactor, thus permitting continued operation of the unit. The catalyst
in the replaced reactor is then regenerated by admitting hot air into
the reactor to burn the carbon off the catalyst. After regeneration,
this reactor becomes the swing reactor.
8.2.1 Catalytic Reformer, Semi-Regenerative
The major pieces of equipment are three reactors operating in series,
each preceded by a fired heater, a hydrogen separator, a stabilizer
column, a hydrogen circulating compressor, pumps, and various
heat exchangers. See Figure 8.1.
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Figure 8.1 Catalytic Reforming, Semi-Regenerative
The feed stream consisting of heavy straight run gasoline and/or
naphtha (boiling range 180F to 375ºF [82C to 191C]) has been
pretreated by hydrotreating in a reactor (not shown in Figure 8.1)
charged with a cobalt-molybdenum catalyst. In this reactor, organic
sulfur and hydrogen compounds are converted to hydrogen sulfide
and ammonia, both of which are gases at process conditions. Metals
in the feed are retained on the catalyst bed.
The liquid feed is pumped to the hydrogen cycle pressure and
commingled with the recycled hydrogen. The commingled stream is
passed through the heaters and reactors in series. The initial reaction
is endothermic, and a large drop in temperature occurs. As the
charge proceeds through the reactors, the reaction rate decreases, the
reactors become larger and the reheat needs become less.
The reaction mixture from the last reactor is cooled and the liquid
products condensed. The two-phase mixture is routed to a separator;
the hydrogen exits from the top of the separator, carrying with it
some of the hydrogen sulfide and ammonia. The hydrogen stream is
split into a hydrogen recycle stream and a net hydrogen product,
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Catalytic Reforming Units
which is used elsewhere in the refinery. A portion of the net
hydrogen is used in the feed pretreatment.
The liquid phase from the separator is routed to the stabilizer. The
bottom product from the stabilizer is the sought-after reformate. The
top product is gas, which is largely butane and lighter components;
this is routed to a gas processing unit or to plant fuel.
8.3 Reactor Design
A typical reactor is shown in Figure 8.2. The design is cold shell,
i.e., the insulation is on the inside. Hot shell design has the
insulation on the outside. Cold shell design insulates the pressurecontaining shell from the hot reaction temperature and permits a
thinner shell wall. The refractory insulation is separated from the
process stream by stainless steel shrouding.
Figure 8.2 Cold Shell Reactor
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In Figure 8.2, note the vapor distribution baffles and the inert
ceramic spheres. These promote the even distribution of flow into,
through, and out of the catalyst bed. This is to insure intimate
contact with all of the catalyst and low pressure drop through the
reactor.
Temperature measurement using thermocouples at three different
elevations in the catalyst bed is essential for surveillance of catalyst
activity and as an aid in monitoring coke burn-off during
regeneration.
8.4 Corrosion Phenomena in Catalytic
Reformers
Equipment in catalytic reformers is vulnerable to high temperature
hydrogen attack (HTHA), corrosion caused by hydrogen sulfide and
hydrogen chloride, stress corrosion cracking, and fouling. The
temperature, pressure, and composition of the stream influence the
corrosiveness of the fluid. High pressures are required primarily to
maintain the hydrogen partial pressure necessary to obtain the
desired reactions. Changes in stream and phase velocity also play a
significant role in several corrosion phenomena.
The pretreatment process (hydrotreating) is not 100% efficient, and
small traces of organic elements containing sulfur and nitrogen pass
on to the reformer. The operating conditions present in the catalytic
reformer produce hydrogen sulfide gas from the organic sulfur
compounds and ammonia from the nitrogen-bearing compounds.
Hydrogen chloride is also produced when small amounts of water in
the stream strip some of the chloride from the catalyst.
Solid ammonium chloride is formed on surfaces as the effluent
stream is cooled down. This salt produces fouling, resulting in a loss
of heat transfer in heat exchangers. Ammonium chloride may even
plug some small passages, such as those in compressors, causing an
unscheduled shutdown of the unit.
8.4.1 High Temperature Hydrogen Attack
(HTHA)
Operating conditions in catalytic reforming processes provide the
conditions for a type of metal attack unique to this process. The
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conditions are high temperature, high pressure, and a hydrogen-rich
process fluid. This type of attack is termed high temperature
hydrogen attack (HTHA), which can cause catastrophic damage to
most of the metals and alloys commonly used in refinery
construction.
The importance of this type of attack has prompted the American
Petroleum Institute (API) to collect data documenting the
experience of many refiners encountering this problem. The results
have been published in API Recommended Practice 941, “Steels for
Hydrogen Service at Elevated Temperatures and Pressures in
Petroleum Refineries and Petrochemical Plants.” (Washington,
D.C.: American Petroleum Institute, 1997). API 941 is found in
Appendix O. This document provides a comprehensive guide based
on the experience of others in selecting materials to resist HTHA.
Engineering personnel encountering these process conditions will
find it a valuable source of information.
8.4.2 Stress Corrosion Cracking
Three types of stress corrosion cracking (SCC) can occur in
catalytic reforming units. They are:
•
SCC by ammonia—Ammonia, present in the effluent from both
pretreatment and the reforming reactors, dissolves in water to
form ammonium hydroxide. Ammonium hydroxide causes
rapid corrosion and SCC of copper-base alloys.
•
SCC by chlorides—Can occur on centrifugal compressor rotors
as a result of acidic chloride solutions formed when ammonium
chloride deposits are exposed to moisture and air during shutdowns.
•
Hydrogen embrittlement (sulfide stress cracking [SSC])—May
be related to fatigue cracking of small diameter piping adjacent
to compressors and is suspected of causing valve failures in
reciprocating recycle hydrogen compressors. SSC, which is a
form of hydrogen embrittlement, can occur in high-strength
bolts, such as ASTM A 193 B71 bolts, in catalytic reformers.
SSC may also cause failures in 12% chromium steel valve trim.
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8.5 Materials of Construction
The majority of the equipment and piping in a catalytic reformer is
made of carbon steel unless the temperature is above 500ºF (260ºC).
The presence of hydrogen requires the use of low-alloy steels
containing chromium, which prevent HTHA above 500ºF (260ºC).
Stainless steel may also be used for internal surfaces that may come
in contact with a mixture of hydrogen sulfide and hydrogen, which
causes high-temperature sulfidation of steel. However, with
stainless steel, an iron sulfide film may be formed that, when
exposed to moist air during a shutdown or turnaround, reacts to
form polythionic acid on the surface. If the stainless steel is
sensitized, the metal may spontaneously crack due to the
combination of tension stresses and corrosion.
8.5.1 Reactors
Reactors are heavy-walled vessels fabricated from chrome-bearing
steels. The exact level of chromium needed to resist hydrogen attack
depends on the operating pressure and partial pressure of hydrogen.
As mentioned previously, API RP 941, publishes design curves that
are used to select the appropriate alloy.
Reactors of the cold shell type have internal insulation, which is
separated from the process stream by austenitic stainless steel
shrouding. Type 321 stabilized grade is used if the shrouding is
welded. Hot shell reactors may be clad internally with either type
321 or weld overlaid with type 347 stainless steel since sulfur
breakthrough may occur despite pretreatment. Also, the catalyst is
presulfided for best performance with mixtures of hydrogen and
hydrogen sulfide gases. Low-chrome steels are subject to hightemperature sulfidation in these environments.
8.5.2 Exchangers and Piping
Heat exchanger metallurgy varies with stream composition and
temperature. Feed/effluent exchangers and associated piping have to
resist hydrogen on the feed side and hydrogen sulfide/hydrogen
streams on the effluent side. Below 500ºF (260ºC), carbon steel may
be used for the shell. A chrome-moly alloy is required above 500ºF
(260ºC).
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Tubes and tube sheets are made from type 304 stainless steel to
handle the effluent, which is more corrosive than the feed. The
channel is made from a chrome-moly alloy, which may be clad with
either type 321 or type 347 stainless steel.
Effluent coolers and other low-temperature exchangers are
fabricated from carbon steel due to improved water treatment
practices. Previously, duplex tubing was used for coolers, with brass
on the water side and carbon steel on the process side. Solid brass
tubing, if used, is subject to SCC by the traces of ammonia found in
the effluent.
Piping carrying streams with hydrogen present should be made from
1-1/4 Cr-1/2 Mo or 2-1/4 Cr-1/2 Mo steel for temperatures above
approximately 500ºF (260ºC). Below this temperature, carbon steel
may be used. Type 5 Cr-1/2 Mo alloy piping is used if the oil charge
is being transported without hydrogen, with the temperature above
550ºF (288ºC). If the temperature is above 700ºF (370ºC), 9 Cr-1
Mo alloy is used to combat high-temperature sulfidation.
Valve bodies are matched to the piping in which they are
incorporated, with the trim being at least 12% chrome. Higher alloys
may be necessary due to traces of hydrogen chloride in recycle
gases.
8.5.3 Fired Heaters and Other Equipment
Heater tubes are subject to high-temperature corrosion both on the
process side and in the fire-box. 2-1/4 Cr-1 Mo alloy is commonly
used to resist hydrogen attack in furnace tubing while providing
good oxidation resistance externally. Tube supports and hangers are
fabricated from cast alloys ranging from HH alloy (25% chrome12% nickel) to 50 Cr-50 Ni alloy, which is used to resist fuel ash
corrosion.
Rotating equipment, such as pumps and compressors, are alloyed to
resist hydrogen and hydrogen sulfide attack. Hardness of highstrength steel parts should be controlled to 225HB or lower in weld
and heat-affected zones to avoid SSC.
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8.6 Corrosion Control
In catalytic reforming units, corrosion is usually at a minimum
during operation since the higher temperatures do not allow
condensation of corrosive agents. In addition, the equipment at
lower temperatures is sufficiently dry so that any salts that condense
are not very aggressive. Problems develop when the unit is shut
down. To avoid corrosion during shutdowns, equipment is water
washed with 5 wt% sodium bicarbonate solution. Equipment that is
water washed includes:
•
Effluent coolers
•
Flash drums or separators
•
Recycle compressors
•
Strippers and associated piping.
The alkalinity of the sodium bicarbonate solution used for water
washing overcomes the acid hydrolysis of ammonium chloride
when water is introduced into previously dry equipment. In order to
remove hydrogen chloride from recycle gasses, HCl traps, which are
proprietary adsorbents, may be installed in the lines leading from
the separators. Modified alumina containing sodium aluminate,
which is a strong base, is a common adsorbent. Adsorber beds can
become readily plugged with traces of ammonium chloride if the
stream being cleaned is liquid or if the vapor temperature is below
the condensation temperature for the salt.
With modern catalytic reformers, as much as a ton of hydrochloric
acid must be disposed of before the catalyst regeneration sequence
is complete. Large quantities of sodium hydroxide or sodium
carbonate can be injected during catalyst regeneration periods to
neutralize hydrochloric acid. Hydrochloric acid reacts with the
neutralizing compounds to produce sodium chloride. The resulting
alkaline solution is somewhat corrosive due to the presence of
oxygen that is in the gases admitted to the reactors to burn the coke
or control the metallic catalyst.
Most problems that occur during the catalyst regeneration period are
related to one or more of the following factors:
•
Poor mixing—Injecting the neutralizer as far upstream of the
effluent coolers as possible and having a secondary injection
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Catalytic Reforming Units
point just ahead of the coolers enhance mixing of the injected
neutralizer with the acid vapors.
•
Insufficient neutralizer—Pump and line sizes should have the
capacity to handle ten times the necessary base injection to neutralize the acid if it were given at a uniform rate from the catalyst
bed.
•
Inadequate pH control—pH should be controlled between 10
and 11. pH should be checked as the liquid leaves the effluent
coolers and not the flash drum because there is a large excess of
base solution in the drum compared with the solution that has
just come in contact with the acid gases at the coolers. If the catalyst is being presulfided, the pH must be between 11 and 12 due
to hydrolysis of sodium sulfide.
•
No corrosion monitoring—On-line corrosion monitoring with
conventional electrical resistance probes can greatly assist in
controlling neutralizer injection.
8.7 Corrosion Monitoring
During catalyst regeneration, corrosion monitoring probes are
sensitive to changes in the corrosivity of the acid vapor stream and
allow adjustment of the injected neutralizer for proper control of
corrosion. The probes detect large uncontacted masses of acid gas
passing throughout the piping, warning of insufficient neutralization
caused by poor mixing or insufficient base solution.
Other than corrosion monitoring during catalyst regeneration, the
catalytic reforming unit does not require corrosion monitoring
during unit operation since the corrosive agents present are not
reactive. However, it is useful to determine the chloride content of
various streams to detect unusually high concentrations, which may
cause a problem in the reformer or in another refinery unit. Chloride
traps, if present, should be monitored regularly to determine when
the adsorber bed needs replacement.
If equipment is water washed, the solutions should be analyzed for
chloride content to determine the success of the washing process.
Sodium bicarbonate, if used, can be rinsed out with boiler feed
water. The water conductivity can then be used to determine if the
equipment is chloride-free.
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8.8 Inspection in Catalytic Reformers
Several inspection techniques can be used in catalytic reforming
units. They include:
•
Radiography (RT), ultrasonic shear wave, ultrasonic attenuation,
and metallography (in-situ or boat samples)— Used to detect
hydrogen damage of chrome-bearing steels used to fabricate catalytic reforming reactors.
•
Ultrasonic thickness (UT) tests—Used during shutdowns to
measure the wall thickness of equipment and piping to determine
if the corrosion allowance included in the original design and
construction is still in place.
•
Scanning UT methods (C-scan, B-scan), RT, or newer inspection
methods using electrical resistance—Used to evaluate an area
for pitting or stress corrosion cracking.
•
Visual inspection—One of the best ways to look for localized
attack, especially pitting and flow-influenced corrosion.
•
Wet fluorescent magnetic particle testing (WFMT)—Used to
locate fine cracks associated with hydrogen sulfide cracking
under wet conditions.
References
1. ASTM A193 B7, “Standard Specification for Alloy-Steel and
Stainless Steel Bolting Materials for High-Temperature
Service” (West Conshohocken, PA: ASTM, 1999)
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Chapter 9:Delayed Coking Units
Objectives
Upon completing this chapter, you will be able to do the following:
•
Identify the purpose of the delayed coking unit
•
Discuss the benefits associated with the coking process
•
Identify the main pieces of equipment found in a delayed coking
unit
•
Describe the process flow in a delayed coking unit and identify
the operating parameters for the coking process
•
Identify crude components and other contaminants which are
likely to cause corrosion problems in a delayed coking unit
•
Identify types of corrosion and failure mechanisms found in
delayed coking units and discuss solutions adopted to minimize
these problems
•
Identify inspection procedures often employed in delayed coking
units.
9.1 Introduction
Delayed coking is a thermal cracking process used to transform
reduced crude oil from the crude distillation unit into lighter
fractions suitable for processing into more profitable products, such
as kerosene, gasoline, and liquefied petroleum gases. In the process,
the heavier components of the reduced crude are thermally cracked
into carbon (coke), and the lighter components are transformed into
hydrocarbon compounds, namely gas oil and naphtha, which
provide increased feed to downstream units producing gasoline.
Ongoing development during the first half of the twentieth century
led to the design of heaters in which higher temperatures could be
achieved without significant coke formation in the heater tubes. By
providing an insulated surge drum on the outlet of the heaters,
sufficient retention time was obtained to permit the coke formation
reaction to be essentially completed in the drum. This minimized
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Delayed Coking Units
the carryover of the coking process into downstream units, such as
catalytic cracking units. Carryover of the coke formation into such
units results in adverse effects on the catalytic process.
World War II and subsequent years saw the rapid development of
industries requiring carbon anodes and electrodes. For example,
carbon anodes are used for aluminum manufacture. Coke is also
used to produce calcium carbide, titanium, and silicon carbide
electrodes for arc furnaces in making stainless steels, as a
recarburizing agent in iron and steel, and in the cement industry. As
a result, coke has become a profitable product of refineries.
In addition to the production of coke for sale, additional benefits are
realized. Production of the quantity and quality of gas oil as a feed
to catalytic cracking units is enhanced. The coking process tends to
concentrate in the coke undesirable components, such as sulfur and
nitrogen compounds, olefins, inorganic salts, and heavy metal
contaminants. While this increases the corrosion problems in the
coking unit, the problems in the catalytic cracking unit are
substantially decreased.
9.2 Equipment and Operation of the
Delayed Coking Unit
The principal feed to the delayed coking unit is reduced crude from
the bottoms of the crude distillation and/or vacuum distillation
columns. Some recycle streams from downstream refinery units are
sometimes added to the main feed stream.
The feed stream enters the fractionator two to four trays from the
bottom vapor zone. See Figure 9.1.
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Figure 9.1 Delayed Coking Unit
The hot recycled gas stream, which enters under the bottom tray, is
quenched by the cooler liquid descending from the trays above.
Liquid from the bottom of the fractionator is pumped through the
direct-fired heater. The temperature is raised to 925F (496C).
Steam is injected into the heater tubes to increase the velocity of the
combined stream to minimize coke formation in the tubes. From the
heater, the stream enters one of the two parallel coke drums. The
large diameter of the drums increases the residence time at the high
temperature. This delay in the passage of the stream through the
drum permits the continued formation of coke and gives rise to the
term delayed coking. The hot gases leaving the top of the drum
reenter the bottom of the fractionator, thus completing the cycle.
Coke drums are operated in pairs. Normally, one coke drum is in
service for twenty-four hours. During this time, coke is removed
from the other coke drum. Removal is accomplished by either
mechanical or hydraulic means. In the latter, high-pressure water
jets are used to cut the coke into pieces to be carried out the bottom
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of the drum. At the end of the twenty-four hour period, the newly
emptied drum is placed in service, and the drum that was onstream
is decoked.
The fractionator and the gas oil stripper operate in parallel. The hot
recycled vapors from the coke drum rise in the fractionator
following the partial quench by the fresh feed. The vapors are
further cooled by liquid withdrawn from the bottom tray of the top
section of the fractionator, pumped and cooled, and reintroduced
under the same tray. Vapors leaving the top of the fractionator are
cooled and partially condensed. The liquid phase is used as cooling
reflux for the top section of the fractionator. The excess liquid is
taken off as unfinished naphtha product. The uncondensed vapor
phase is removed as gas oil for further treating or as fuel gas.
A portion of the liquid drawn off the bottom tray of the top section
of the fractionator is fed to the gas oil stripper. Light components
from the stripper are recycled to the fractionator; further stripping in
the stripper results from the injection of steam into the bottom of the
stripper. Bottom product from the stripper is taken off as gas oil and
sent to the catalytic cracking unit for production of higher octane
gasoline.
9.3 Corrosion and Other Problems in
Delayed Coking Units
The coking unit is a bottoms stream processing unit and more of the
undesirable components of crude oil tend to be concentrated in the
heavier fractions. The problem components are:
•
Sulfur compounds
•
Nitrogen compounds
•
Olefins
•
Inorganic salts
•
Heavy metal contaminants.
In addition, streams recycled from downstream refinery units can
carry refining additives or other undesirable materials into the
coking unit feed. As a result, the coking unit is vulnerable to a
number of corrosion problems, including:
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Delayed Coking Units
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•
High-temperature sulfur corrosion
•
Naphthenic acid corrosion
•
High-temperature oxidation/carburization/sulfidation
•
Erosion-corrosion
•
Aqueous corrosion.
The batch-type operation of the coke drums makes them unique
among refinery equipment. The cyclic nature of the coke drum
operation results in a number of mechanical and metallurgical
degradation problems unique to coke drums, such as:
•
Thermal fatigue cracking
•
Bulging
•
Temper embrittlement
•
Quench embrittlement.
9.3.1 High-Temperature Sulfur Corrosion
High-temperature sulfur corrosion usually manifests itself as
general uniform thinning throughout the system. It can affect coke
drums, furnace tubes, and furnace feed, transfer, drum switch, and
coke drum overhead piping. Adding 5% or more chromium to
carbon steel materials helps prevent high-temperature sulfur
corrosion, which occurs at temperatures above 400F (204C).
Coke drums are usually constructed of carbon or 1-1/4 Cr-1 Mo
alloy steel internally clad with type 410S or type 405 stainless steel.
Nickel alloy 600 weld overlay is used in the weld areas to protect
against high-temperature sulfur corrosion. Process piping is
typically specified as 5% Cr-Mo or 9% Cr-Mo alloy steel depending
on the sulfur content of the coker charge. Sulfur levels greater than
3.0 wt% generally require a minimum of 9 Cr alloy for process
piping to provide adequate protection from high-temperature sulfur
corrosion. Coker heater tubes are usually specified as 5 Cr or 9 Cr
alloy steel to resist high-temperature sulfur corrosion as well as
oxidation, creep, and stress rupture.
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Delayed Coking Units
9.3.2 Naphthenic Acid Corrosion
Naphthenic acid corrosion, which is normally manifested as highly
localized deep pitting without deposit formation, is caused by
naphthenic and other organic acids present in the coker feed. This
type of corrosion is most severe in areas of high velocity or areas
where metal temperatures during operation are near the boiling/
condensation point (450F to 600F [232C to 315C]) of the
organic acids present in the process stream.
Naphthenic acid corrosion is limited to piping and equipment in the
feed preheat exchangers, pumps, piping, and the heater inlet piping
because it is destroyed by the thermal cracking reaction that occurs
in the coker heater. In addition, due to the protective coke layer on
the interior diameter of coker heater tubes, naphthenic acid
corrosion is seldom observed in this area.
For those areas susceptible to this type of corrosion, resistance is
achieved by the use of various high-alloy steels. The acid content of
the feed determines the alloy used. For example, for feedstocks
with neutralization numbers less than 1.5, 9 Cr-1 Mo steels provide
adequate corrosion resistance. When neutralization numbers are
greater than 1.5, severe corrosion can occur and 300 series stainless
steels containing a minimum of 2.5% Mo, such as type 316 and type
317, are required. When welding is called for, low carbon or “L”
grade base metals and filler metals are normally specified.
9.3.3 High-Temperature Oxidation/Carburization/Sulfidation
These types of corrosion occur at temperatures above 950F
(510C) and are generally limited to the coker heater tubes and
heater parts, such as burners and tube supports. High-temperature
oxidation and sulfidation manifest themselves as a general uniform
thinning or a localized thinning or pitting. Carburization and
quenching during decoking can result in a significant loss of fracture
toughness in the heater tubes. Short-term stress rupture or longterm creep rupture are caused by localized overheating of the tubes
and can result in localized bulging and cracking.
Coker heaters generally operate at very high temperatures with
typical process outlet temperatures in the 900F to 950F (482C to
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510C) range, which result in tube metal temperatures as high as
1400F (760C) depending on the tube material. Because of the
thermal cracking reaction taking place in the coker heater tubes, the
tubes gradually build up a layer of coke on the inside. Coke buildup
inside the tubes can cause excessive pressure drops through the
furnace and excessively high tube skin temperatures of greater than
1350F (732C). These high temperatures can result in material
deterioration due to oxidation, sulfidation, carburization, creep, and
stress rupture. Therefore, heater tubes are normally decoked before
tube skin temperatures become high enough to cause premature
failure.
9.3.3.1 Decoking Heater Tubes
Two methods of decoking are commonly used:
•
Steam air decoking
•
Steam spalling.
Steam air decoking involves shutting off the process feed to the
heater, continuing to fire the furnace, and starting a flow of steam
through the tubes. Air is then added at a controlled rate to remove
the coke gradually by burning. Tube skin temperatures during
steam air decoking can reach 1600F (871C) and, if not properly
controlled, can severely damage the heater tubes. The tubes are
cooled by steam injection.
The second decoking method, steam spalling, is now being used in
many coker units. Steam spalling offers several advantages,
including:
•
Lower heater tube skin temperatures for longer periods of time
•
Less potential for tube damage due to lower temperatures
•
Accomplished without removing the entire heater from service
since only one coil is spalled at a time
•
Fewer unit shutdowns than for steam air decoking.
Spalling involves removing process feed from one pass and
injecting a source of water. The heater pass temperature is
fluctuated to allow flaking off of coke due to the expansion and
contraction of the tube.
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Delayed Coking Units
Damage observed in coker heater tubes is usually the result of
overheating either during operation or decoking. Typical damage
includes bowing or buckling of the tubes between supports, severe
oxidation or scaling, localized bulging and/or cracking due to creep/
stress rupture, or brittle fracture caused by loss of ductility due to
carburization or quench embrittlement.
9 Cr-1 Mo tubes are typically used for coker heater service. Some
refiners have used an aluminum diffusion coating on both the
outside diameter and inside diameter of the heater tubes to improve
resistance to carburization and oxidation. An aluminum diffusion
coating also improves resistance to high-temperature sulfidation,
but has resulted in the loss of ductility in some 9 Cr tubes. The
ductility can be restored with a heat treatment of 1750F (954C) for
about 30 minutes, air cooling, and tempering at 1350F (732C).
9.3.4 Erosion-Corrosion
Erosion-corrosion can occur in high-velocity areas in piping,
especially in the coker heater tube bends and where injection quills
or thermowells protrude into the piping causing turbulence. Erosion
in these areas can be very rapid, especially during spalling and/or
steam air decoking due to erosion by coke particles as they are
removed from the heater tubes.
9.3.5 Aqueous Corrosion
The equipment in the delayed coking unit is susceptible to a number
of low-temperature aqueous corrosion mechanisms, including:
•
Wet sulfide cracking (hydrogen induced cracking[HIC], stress
oriented hydrogen induced cracking[SOHIC], sulfide stress
cracking[SSC])
•
Ammonium chloride/ammonium bisulfide corrosion
•
Ammonia stress cracking of copper-based alloys
•
Chloride stress corrosion cracking of austenitic stainless steels.
In delayed coking units nearly all the equipment is exposed to
conditions promoting these forms of corrosion at some point during
the operation. The cold sections (temperatures less than 400F
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Delayed Coking Units
9-9
[204C]) of the fractionation section are continuously exposed to
these environments.
In the coke drum section, these corrosion mechanisms occur only
during water quench, steam out, and blowdown portions of the
operation.
However, since all coke drums normally share
blowdown piping and drums, they are exposed to the wet blowdown
vapors and liquids on a nearly continuous basis. The quench water
and blowdown vapors and liquids usually contain large amounts of
hydrogen sulfide, ammonia, ammonium chloride, ammonium
hydrosulfide, and cyanides released from the coker feed by the
thermal cracking reactions. In addition, during the water quench
cycle, the type 410S stainless steel internal cladding normally used
for coke drums is exposed to water containing large amounts of
hydrogen sulfide and ammonia salts and, therefore, is susceptible to
sulfide stress corrosion cracking. This occurs particularly in areas
adjacent to the nickel alloy 600 weld overlay used to cover the girth
and longitudinal weld seams. Carbon steel blowdown piping and
vessels can also suffer corrosion if the chloride salt content in the
blowdown water exceeds 1000 ppm.
Many of the towers, drums, and exchangers in the coker unit are
susceptible to hydrogen blistering. Hydrogen sulfide is the
component in the process streams that contributes to hydrogen
blistering, with some pitting in towers and receivers.
Ammonia stress corrosion cracking of copper alloy tubes may occur
in the exchangers where the pH is high due to ammonia content.
Galvanic corrosion may occur where dissimilar metals are used in
condensers and coolers.
9.3.6 Corrosion Under Insulation (CUI)
Much of the piping and equipment in a delayed coking unit is
susceptible to CUI due to the cyclic nature of coker operations. The
top head of the coker drums is particularly susceptible to CUI from
the cutting water, which is periodically dumped on top of the drums
during the cutting cycle. The blowdown system is also highly
susceptible to CUI because it is in cyclic service with temperatures
ranging from 100F to 800F (37.8C to 426C). All insulation
must be properly jacketed and sealed to prevent water intrusion. In
addition, to protect against CUI, insulated equipment operating
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Delayed Coking Units
below 250F (121C) or in cyclic temperature service should be
coated with a corrosion-resistant coating prior to insulating.
9.3.7 Thermal Fatigue, and Temper Embrittlement of Cr-Mo Steels
Frequent thermal cycling (temperatures from 100F to 900F
[37.8C to 482C]) experienced during coke drum operation can
result in a variety of damage mechanisms, including:
•
Bulging and distortion of shell plates, typically 20 ft. to 40 ft.
above the skirt attachment weld
•
Circumferential cracking adjacent to welds and bulges, both outside diameter and inside diameter initiated
•
Cracking and bulging in the area of the skirt-to-shell attachment
weld.
Cr-Mo steel coke drums may also suffer a loss of fracture toughness
caused by long-term exposure to high temperatures and stresses
(temper embrittlement), which can lead to increased fatigue crack
propagation rates. The primary life limiting factors for coke drums
are as follows:
•
Low cycle fatigue endurance limit (total number of cycles)
•
Reduction of wall thickness due to the yielding associated with
bulging
•
Structural failure (squatting and/or leaning of the drum due to
bulge collapse).
Coke drums are normally operated until the:
•
Frequency and severity of through-wall fatigue cracks in the
shell and nozzles increase to a point considered unsafe
•
Bulging and distortion are so severe that the drums are considered to be structurally unsound
•
Distortion is so severe that the piping can no longer be connected
to the drums due to misalignment.
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9.4 Inspection of Coking Units
9.4.1 General Inspection
With the exception of the coke drums, inspection procedures for
delayed coking units are similar to those for other refinery units
subject to high-temperature sulfur corrosion and wet sulfide
cracking. Inspectors should look for coking, external oxidation,
internal sulfidation, carburization, and stress/creep rupture in the
coker heater tubes, which are normally 5% Cr to 9% Cr. Transfer
piping (5% Cr to 9% Cr) should be inspected for thinning.
Coke drums, which are made of carbon steel, C-1/2 Mo, or 1-1/4 Cr
with type 405 or type 410S cladding, should be inspected for
thermal fatigue stresses and shocks displayed as bulging of the
vessel walls and cracking of the weld areas. Inspection of the
fractionator and other vessels, which are typically constructed of
carbon steel with the lower section of the towers lined with type 405
or type 410S cladding, involve checking clad/lined and unlined
areas of the vessel walls and the internals for corrosion, blistering,
and cracking.
Standard inspection methods such as ultrasonic testing (UT),
magnetic particle testing (MT), and dye penetrant testing (PT) are
used.
9.4.2 Coke Drum Inspection
Specific areas in coke drums that should be inspected for bulges
and/or fatigue cracks include:
•
20 ft. to 40 ft. above the bottom cone-to-shell weld or in the area
of the skirt-to-shell attachment weld
•
Nozzles on the top head at the nozzle-to-shell attachment
•
Coke drum cladding damaged by a dropped drill stem or disbonded from the base material after years of service
•
Support-skirt-to-drum weld
•
Top of the vertical expansion slots within the skirt
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•
Delayed Coking Units
Coke chutes, located just below the coke drums, as a result of
impact and wear from coke falling after it has been cut from the
drum.
Cracks in coke drums may initiate on the external or internal surface
of the drums and are initially shallow, but will increase in both depth
and length with time. Crack growth rates are determined by a
number of factors, including metallurgy, cycle frequency, operating
temperature, and pressure. Stainless steels (type 410S or type 405)
used to clad coke drums become brittle when exposed to
temperatures in the range of 850F to 950F (454C to 510C) and
are more susceptible to crack initiation and display increased crack
propagation rates.
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Amine Treating Units
10-1
Chapter 10:Amine Treating Units
Objectives
Upon completing this chapter, you will be able to do the following:
•
Discuss the purpose of a refinery amine treating unit (amine
unit)
•
Discuss applications for common types of amines in amine units
•
Identify amine equipment and describe the amine process
•
Identify and discuss corrosion phenomena common to amine
units
•
Identify and discuss the corrosive species in amine units
•
Discuss types of corrosion inhibitors used in amine units
•
Identify materials of construction for equipment and piping in
amine units
•
Identify corrosion monitoring techniques, as well as areas that
are typically monitored
•
Discuss corrosion control measures in amine units.
10.1 Introduction
Amine treating units are used throughout modern refineries to
remove hydrogen sulfide, mercaptans, carbon dioxide, and certain
other compounds from hydrocarbon process streams. An amine unit
typically processes gas streams from the crude unit, coker, fluid
catalytic cracker, and hydrotreating process units as well as liquid
hydrocarbon streams, such as mixed C3 and C4 light hydrocarbons.
The wide variety of feed streams processed by an amine unit has
resulted in numerous alkanolamine-based processes.
Amine units use chemical solvent processes that depend on
reversible chemical reactions. Acid gases, such as hydrogen sulfide
(H2S) and carbon dioxide (CO2), are absorbed into the amine
solution by chemical reaction resulting in dissolved amine salts.
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Amine Treating Units
This reaction is easily reversible for weak acids like H2S and CO2
by increasing the temperature and lowering the pressure of the
amine solution.
Amine units also remove certain other compounds that contribute to
corrosion, fouling, and reduced operating efficiency. However, the
reaction of stronger acids, such as formic acid or thiosulfurous acid,
with the amine solution is much more difficult to reverse. The
resulting amine salts are called heat stable because the acids cannot
be removed under the normal operating conditions of the process.
10.2 Types of Amines Used
The most common amines utilized in refinery treaters include:
•
Monoethanol amine (MEA)
•
Diethanol amine (DEA)
•
Diisopropanol amine (DIPA)
•
Methyl diethanol amine (MDEA)
•
2-(2-aminoethoxy) ethanol (DIGLYCOLAMINE® [DGA]).
[Note: DIGLYCOLAMINE is a registered trade name of Huntsman Corporation for 2-(2-aminoethoxy) ethanol.]
Each amine has certain properties that may make it the appropriate
choice for a specific amine treating application. The following
equations show the acid gas absorption reactions for DEA and
MDEA.
Primary and Secondary Amines (DEA)
(HOCH2CH2)2NH + H2S(HOCH2CH2)2NH2+ + HS-
[10.1]
(HOCH2CH2)2NH + H2O + CO2(HOCH2CH2)2NH2+ + HCO3S-
[10.2]
2(HOCH2CH2)2NH + CO2(HOCH2CH2)2NCO2 + (HOCH2CH2)2NH2
[10.3]
Tertiary Amines (MDEA)
(HOCH2CH2)2NCH3 + H2S((HOCH2CH2)2NCH3)H+ + HS-
[10.4]
(HOCH2CH2)2NCH3 + H2O + CO2((HOCH2CH2)2NCH3)H+ + HCO3S-
[10.5]
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MEA, a primary amine, removes H2S, CO2, and mercaptans with
good efficiency. MEA tends to degrade more rapidly than other
amines when used in CO2 service. MEA forms irreversible
degradation products with CO2, carbon disulfide (CS2), and
carbonyl sulfide (COS), which require continuous atmospheric
reclaiming. MEA is not measurably more effective in removing
mercaptans, such as COS and CS2, than most other amines,
including DEA and MDEA.
DEA, a secondary amine, is probably the most widely employed
amine and is frequently used in refinery amine systems upstream of
the sulfur plant. DEA is resistant to degradation caused by reactions
with COS, CS2, and somewhat by CO2. DEA removes H2S,
mercaptans, and CO2. DEA has the lowest hydrocarbon solubility
at comparable molar concentrations of the common alkanolamines.
DEA cannot be reclaimed by atmospheric distillation.
MDEA is a tertiary amine used most often in sulfur plant tail gas
amine units that require selective removal of H2S. MDEA reacts
with H2S like any amine, but reacts much more slowly with CO2.
This difference in reaction rates allows MDEA to selectively
remove more H2S than CO2 if the unit is properly designed and
operated. MDEA is a larger amine molecule and, thus, a higher
weight concentration must be used to achieve similar treating
capacity. MDEA has poor absorption of COS and CS2 and exhibits
significant hydrocarbon solubility.
DIPA is a secondary amine, which was the first to be utilized
commercially to selectively remove H2S. Many amine units using
DIPA have switched to MDEA. DIPA is used primarily in sulfur
plant tail gas units. DIPA is reported to degrade rapidly enough in
CO2 service to require frequent reclaiming by vacuum distillation.
DGA is a primary amine that is utilized when COS and CS2, in
addition to H2S and CO2, must be lowered in concentration. DGA
is reclaimed by atmospheric distillation when in CO2, COS, or CS2
service. DGA is similar to MEA in many ways, but is typically used
at higher molar concentrations due to its lower vapor pressure.
Specialty amines are increasingly popular because they can often
provide increased performance or meet unique needs compared to a
single amine. Specialty amines are usually blends of MDEA or
DIPA with other amines, often with additives to enhance
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Amine Treating Units
performance. One well known example is Sulfinol that consists of
DIPA and sulfolane. (Note: Sulfinol is a registered trade name of a
treating process licensed by Shell.)
All of the alkanolamines discussed react directly with H2S, as
shown in Equation 10.1 through Equation 10.4. The reaction
between the alkanolamines and CO2 differs in that all of the amines
react with carbonic acid (Equation 10.2 and Equation 10.5), but
MDEA and other tertiary amines will not react by the carbamate
mechanism (Equation 3). The additional time required for CO2 to
dissociate to carbonic acid and then react is the principle reason
MDEA can be used to selectively remove H2S while absorbing less
CO2. The selective absorption of H2S is often measured as CO2
slip, which is the percentage of CO2 that is not absorbed.
Caution is required when comparing corrosion data of the different
amines due to the large difference in molecular weights. Laboratory
results comparing MEA at 20 wt% with MDEA at 30 wt% would
not be a reasonable comparison unless the selectivity of MDEA
warranted the use of a 25% less active solution. Ideally, testing
should be conducted at equal molar, equal acid gas removal, or
actual plant concentrations.
10.3 Refinery Amine Process Description
Figure 10.1 presents a generalized flow diagram for a refinery
amine unit. The unit contains a fuel gas absorber, a liquid treater, a
hydrogen recycle absorber, an amine regenerator (sometimes called
stripper), and a flash drum, or more precisely, a three-phase
separator in addition to the required pumps, heat exchangers, and
other associated equipment.
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Amine Treating Units
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Figure 10.1 Refinery Amine Unit with Multiple Absorbers
Gas absorbers typically have 20 trays (or equivalent amount of
packing) unless the absorber is designed specifically for H2S
selectivity. The feed gas enters the absorber through a distributor at
the bottom of the vessel. For maximum gas absorption, the absorber
operates at high pressure and low temperature. The preferred feed
gas temperature range is 80F to 100F (27C to 38C), but
temperatures as high as 130F (54C) are common. The gas moves
upward through the absorber. The amine solution enters the
absorber near the top, also through a distributor. The amine solution
flows downward (counter-current) across the trays and comes in
contact with the gas stream, absorbing the acid gas species in the
process. The amine solution becomes enriched with acid gas and is
usually called rich amine. Other names, such as fat amine, are also
used.
Liquid treaters usually have fewer trays (or equivalent amount of
packing) than gas absorbers. Liquid treaters must balance the need
for good mixing and, thus, good acid absorption with the need for
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Amine Treating Units
good phase separation. The tower liquid level is usually maintained
near the top. The bulk phase is usually the amine solution rather
than the hydrocarbon feed stream, but the reverse is also practiced.
Liquid treaters are operated at temperatures in the 120F to 140F
(49C to 60C) range. The hydrocarbon feed, treated hydrocarbon
product, amine feed, and rich amine enter and exit the treater as
described for gas absorbers.
The rich amine from several absorbers may be commingled in the
flash drum. The flash drum operates at a lower pressure to flash off
soluble light hydrocarbons and aid in the removal of entrained or
condensed hydrocarbons. The flash gas is usually returned to the
refinery fuel gas system. A flash drum with liquid separation
internals is typically called a three-phase separator. Entrained
hydrocarbons can be skimmed from the rich amine to reduce
hydrocarbon buildup in the regenerator or amine filters.
The pressure of the flash drum determines if a rich amine pump is
required to move the rich amine to the regenerator. The rich amine
solution is pressured or pumped through the lean/rich cross heat
exchanger(s). The rich amine is tube side to reduce local pressure
changes that may cause flashing of the amine solution. The rich
amine is typically heated to 180F to 210F (82C to 99C). After
the cross exchanger, the hot rich amine is sent to the top section of
the amine regenerator. A pressure letdown valve is used to reduce
the pressure of the rich amine solution as it enters the regenerator.
The reduction in pressure and the application of heat in the
regenerator strips the acid gas from the amine solution as it flows
down the regenerator. Acid gas is liberated as the reaction
equilibrium is shifted from the salt to amine and acid gas. Stream
stripping reduces the vapor pressure of the acid gas in the vapor
phase, further shifting the reaction equilibrium to amine and acid
gas.
The regenerator overhead stream consists of steam and acid gas at a
temperature of about 210F to 235F (99C to 113C). Most designs
utilize a conventional condenser and accumulator. The steam is
condensed and returned to the regenerator as reflux, typically at
110F to 140F (43C to 60C). The amine solution flows down the
regenerator to the reboiler, which operates at 230F to 260F (110C
to 127C). The majority of the H2S and CO2 is normally removed
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Amine Treating Units
10-7
from the amine solution before it reaches the reboiler. The reboiler
heating medium should be limited to 300F (149C) to reduce
amine thermal degradation; 65 psia saturated steam is typically
specified.
The amine exiting the bottom of the regenerator is called lean amine
due to the low concentration of acid gas remaining. The hot lean
amine is cooled in the lean/rich cross exchanger(s) to about 170F to
190F (77C to 88C). Additional cooling is provided in the lean
amine coolers prior to entry into the absorber(s). The lean amine
temperature entering a gas treater/absorber should be 5F to 10F
(2.7C to 6C) warmer than the feed gas to reduce hydrocarbon
condensation. The lean amine feed to liquid treaters is often about
130F (54C).
Amine solutions should be filtered by both particulate and carbon
filters even when a reclaimer is used routinely, as with MEA. Older
designs principally utilize filtration on the lean amine, perhaps due
to the concern over potential exposure to H2S. Newer amine designs
utilize rich amine filtration which appears to be more effective.
Some designs utilize filtration on both lean and rich amine streams.
Particulate filters remove corrosion products and other solids.
Carbon filters remove surfactants and hydrocarbons. Neither filter
is particularly effective in removing water-soluble organic acids.
Knockout pots located prior to the gas absorber are included in
many designs to remove entrained water and liquid hydrocarbons
from feed streams. Knockout pots can be useful for removing watersoluble compounds, such as organic and inorganic acids and
ammonia.
10.3.1 Tail Gas Units
Tail gas amine units (TGU) are the last opportunity to remove H2S
and other sulfur species from the sulfur plant off-gas before it enters
the atmosphere. Figure 10.2 is a generalized process flow diagram
for a TGU.
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Amine Treating Units
Figure 10.2 Quench Tower and Tail Gas Unit
The most significant differences in a primary amine system and a
TGU are the:
•
Very low pressure of the TGU absorber
•
Composition of the feed gas
•
Need to achieve a very low H2S content in the treated gas.
The TGU absorber operates typically at 5 psig or less as compared
to primary amine unit absorbers that range from about 50 psig up to
over 500 psig (7.25 kPa to 72.5 kPa). The lower operating pressure
reduces the amount of acid gas that will be absorbed per mole of
amine, thus the rich loading is lower for a TGU than most other
systems.
The TGU feed gas contains primarily hydrogen, nitrogen, CO2, and
H2S. Because the acid gas off the TGU stripper is recycled to the
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sulfur plant, absorbing the CO2 is not desired. This means that the
TGU is the only amine system that universally will benefit from a
selective amine solvent, such as MDEA.
10.4 Corrosion Phenomena
Most of the variables that influence corrosion rates in other process
units are important in amine units as well. These variables include:
•
Temperature
•
Velocity
•
Concentration of corrosive species.
(See Chapter 1 for more information).
These three variables cause or contribute to corrosion in amine
units, such as acid gas flashing, formation of heat-stable salts, and
amine degradation. Acid gas flashing is a recurring problem in
amine units because it causes the local metal surface to have a
significantly lower pH than the bulk solution. Acid gas flashing can
occur at pressures and temperatures lower than the boiling point of
the solution. It is caused by temperature increases or pressure
reductions that upset the acid gas/amine reaction equilibrium.
Normally, the high pH of the amine solution creates a relatively
non-corrosive environment for carbon steel in most areas in the
amine unit. However, absorption of H2S, CO2, and stronger acids in
the amine solution locally reduces the pH, resulting in severe acid
corrosion.
Corrosion can be especially aggressive in the high-temperature
areas of the unit. As rich amine is heated in the lean/rich cross
exchanger, the chemical equilibrium between amine, acid gas, and
amine salt is shifted away from the salt, as described previously.
Acid gas flashing is more likely to occur with high rich amine
loadings and a reduction in pressure. Flashing of acid gas produces
a vapor phase containing little amine to prevent low-pH conditions
at the point of re-condensation.
Velocity has both a direct and indirect impact on corrosion.
Increasing velocity increases corrosion directly by physically
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damaging protective iron sulfide scales and increasing the effective
concentration of corrosive compounds. Physical damage to
protective iron sulfide scales increases with the presence of solids or
two-phase flow in the amine solution.
Increasing velocity increases corrosion indirectly by creating areas
of higher and lower local pressure. Local changes in pressure cause
acid gases to flash from the bulk aqueous amine solution. Collapse
of vapor bubbles in piping, pumps, and exchangers (cavitation and
droplet impingement) contributes to the physical damage caused by
flow.
The areas of highest corrosion potential are the reboiler, hot lean
amine piping, lean/rich cross exchanger, hot rich amine piping,
regenerator, and regenerator overhead system. Acid gas flashing,
cavitation, or droplet impingement is possible in all of these areas
due to the high temperature and potential for pressure fluctuations
caused by flow.
10.5 Corrosive Species
Most corrosion in amine units is acidic in nature. Acids that enter
the system include CO2, H2S, and a variety of stronger acids. A
listing of the most common corrosive species is found in Table 10.1.
CO2 and H2S are the corrosive components in the highest
concentration. CO2 has a pKa only slightly lower than H2S, but
experience has proven it to be much more corrosive. Table 10.2
provides a listing of the same information for the common amines.
Table 10.3 presents the corrosion reactions in amine systems.
Table 10.1: Chemical Data on Selected Substances
pKa
Hydrogen Chloride
Sulfuric Acid
Mole Wt.
36.46
96.06
(25C)
-6.1
-3.0
Formula
HCl
H2SO4
Thiocyanic Acid
Thiosulfurous Acid
59.09
114.14
-1.85
0.60
HSCN
H2S2O3
Oxalic Acid
Sulfur Dioxide
90.02
64.06
1.27
1.89
HOOCCOOH
SO2 + H2O
Formic Acid
Glycollic Acid
46.02
76.03
3.75
3.83
HCOOH
CH2OHOOH
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Acetic Acid
60.03
4.76
CH3COOH
Butyric Acid
88.11
4.82
CH3CH2CH2COOH
Propionic Acid
74.05
4.87
CH3CH2COOH
Carbon Dioxide
44.01
6.36
CO2
Hydrogen Sulfide
34.08
6.97
H2 S
Hydrogen Cyanide
27.02
9.21
HCN
Ammonia ion
18.04
9.24
NH4+1
Table 10.2: Chemical Data for Common Amines
Mole Wt.
pKa
(25C) Formula
Methyl diethanol amine (MDEA) 119.16
8.56
(HOCH2CH2)2NCH3
Diethanol amine (DEA)
105.14
8.90
(HOCH2CH2)2NH
Diisopropanol amine (DIPA)
133.19
8.97
(HOCH2CH2CH2)2NH
Diglycolamine (DGA)
105.14
9.50
H(OCH2CH2)2NH2
Monoethanol amine (MEA)
61.08
9.52
HOCH2CH2NH2
Table 10.3: Potential Corrosion Reactions in Amine Units
CARBON DIOXIDE
CO2 + H2O  2(HO)-C=O  H+ + HCO3-
[10.6]
Fe + 2H2CO3-  Fe(HCO3)2 + H2
[10.7]
Fe(HCO3)2 + H2O  Fe(OH)2 + CO2
[10.8]
Fe + (CO2+H2O)  FeCO3
[10.9]
HYDROGEN SULFIDE
Fe  FE+2 + 2e-
[10.10]
H2S  H+ + HS-
[10.11]
FE+2 + HS-  (FeSH)+
[10.12]
(FeSH)+ + HS-  (HS-Fe-SH)
[10.13]
(HS-Fe-SH) + (FeSH) )+  (HS-Fe-S-Fe-SH)
[10.14]
(HS-Fe-S-Fe-SH) + HCl-  (HS-Fe-S-Fe-Cl) + H2S
[10.15]
Fe + H2S  FeS + H2
[10.16]
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OXYGEN
3Fe + 4H2O  Fe3O4 + 4H2 (magnetite)
[10.17]
4Fe + 3O2 + 6H2O  4Fe(OH)3 (ferric hydroxide)
[10.18]
2Fe(OH)3  Fe2O3 + 3H2O (ferric oxide)
[10.19]
ORGANIC ACIDS
Fe(OH)3 +2(CH3COOH)  Fe(C2H3O2)2OH + 2H2O
(ferric acetate)
[10.20]
Fe + 2(CH3COOH)  Fe(CH3COO)2 + H2 (ferrous acetate)
[10.21]
INORGANIC ACIDS
2Fe(OH)3 + 3(H+ + HSO4-)  Fe2(SO4)3 + 6H2O (ferric sulfate)
[10.22]
Fe + H2SO4  FeSO4 + H2 (ferrous sulfate)
[10.23]
FeS + 6HCN  Fe(CN)6-4 + H2S + 4H+
[10.24]
Fe + 2HSCN  Fe(SCN)2 + H2
[10.25]
(ferrous thiocyanate)
2Fe + 6HSCN  Fe2(SCN)6 + 3H2
(ferric thiocyanate)
[10.26]
HEAT STABLE SALTS (HSS)
HCOO- + H+ + (HOCH2CH2)2NH  (HOCH2CH2)2NH2+ + HCOO-
[10.27]
(HOCH2CH2)2NH + H+ + HSO4-  (HOCH2CH2)2NH2+ + HSO4-
[10.28]
STRONG BASE CONTAMINATION
4NaOH + Fe3O4  Na2FeO2 + 2NaFeO2 + 2H2O )
[10.29]
2NaOH + FeS  Fe(OH)2 + Na2S
[10.30]
AMMONIA
NH3 + H2S  NH4+ + HS-
[10.31]
(ammonium bisulfide)
CO2 dissolves into the amine solution and forms carbonic acid
(Equation 10.6). Carbonic acid reacts with iron to form iron
carbonate (Equation 10.7 and Equation 10.8) which usually does not
protect the metal from continued corrosion. Units processing little
or no H2S will produce corrosion products composed of iron
carbonates, iron oxides, and iron hydroxides (Equation 10.7 through
Equation 10.9).
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H2S reacts with iron to form a scale that can be protective against
continued corrosion in many units. The reaction of iron and H2S
(Equation 10.10 through Equation 10.16) is thought to proceed
stepwise and assumes that an iron sulfide polymer forms with a
bisulfide ion terminating each end. The inclusion of another ion,
such as chloride, in the structure terminates its growth and, if
present in high enough concentrations, destroys the scale.
Magnetite scales have been reported in the literature. Magnetite can
form a protective scale as shown in Equation 10.17. Magnetite is
naturally occurring in scales and deposits in systems processing
CO2, but not H2S. Protective magnetite scales are formed at
temperatures above about 230F to 240F (110C to 116C).
Oxygen reacts with all alkanolamines, resulting in the formation of
formic acid, oxalic acid, and, to a lesser extent, acetic acid. High
concentrations of oxygen in the amine may also lead to the
formation of iron oxides and iron hydroxides (Equation 10.18 and
Equation 10.19). Amine sumps and makeup water are a traditional
means of oxygen entry into the amine system. Many feed gases
contain low concentrations of oxygen from the upstream process,
such as the fluid catalytic cracker. The elimination of oxygen from
amine unit feeds, makeup water, and amine storage will reduce
amine degradation and corrosion issues caused by oxygen.
The contamination of the amine solution with acids stronger than
H2S or CO2 changes the corrosion picture entirely. Stronger acid
salts are not efficiently removed in the regenerator and reach the
stripper bottoms, reboiler, and hot lean piping. These acids form
Heat Stable Amine Salts (HSAS) with the amine because they are
essentially not removed by normal unit operation. The acids include
the organic acids of formate, acetate, and oxalate, and the inorganic
acids of chloride, sulfate, cyanide, sulfur dioxide, thiosulfate, and
thiocyanate.
The organic acids are reported to form from reactions of the amine
and oxygen, and from reactions between CO2, carbon monoxide,
oxygen, and light hydrocarbons. These acids are also found in crude
oils and many crude oil fractions, including amine unit feed streams.
The reaction of these acids with iron (Equation 10.20 and Equation
10.21) creates a water-soluble corrosion product.
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Inorganic acids may also be in the feed streams or be formed in the
amine solution. Most liquid and gas feeds to the amine system
contain small concentrations of chloride, sulfate, thiosulfate,
cyanides, and thiocyanides. Feeds from the crude, vacuum, coker,
and fluid catalytic cracking units have been identified as containing
those species. These acids react with iron and iron corrosion
products like iron sulfide (Equation 10.22 through Equation 10.26)
forming both water-soluble and insoluble iron salts.
HSAS represent a loss of gas treating capacity because the amine
cannot absorb acid gas if reacted with another, stronger acid
(Equation 10.27 and Equation 10.28). The term heat stable is not
entirely true because a significant quantity of these salts dissociates
in the regenerator, and the acids can be found in the regenerator
overhead. The acids dissolve in the condensing steam in the
overhead and return to the regenerator tower in the reflux. Systems
that have a top pump-around rather than the traditional condenser
will accumulate large quantities of strong acids in the circulating
water.
Several rules of thumb are used for the maximum allowable
concentration of HSAS before corrective action is required. The
oldest rule set 2% HSAS (as amine) as the safe limit before the onset
of problems. Later, a second rule allowed 10% of the amine
concentration to be the safe limit. This second rule appears to be a
modification of the first and was developed for DEA and other
amines as they became popular commercially. Experience indicates
that DEA can usually operate with HSAS up to 10% of the amine
concentration (28% DEA; 0.1 = 2.8 wt% HSAS as DEA), but
MDEA should be limited to a lower concentration.
HSAS concentration is most often controlled by normal amine
solution losses, amine reclamation, or intentional purging of amine
solution or reflux. HSAS are selectively removed from the amine
solution by atmospheric distillation, vacuum distillation, ion
exchange, and proprietary methods. All of these practices are
beneficial from a corrosion point of view.
Neutralization of the HSAS insitu is a common industry practice to
restore acid gas removal capacity. The impact of neutralized HSAS
on corrosion is a current industry concern. Adding a strong base,
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such as sodium hydroxide, will restore acid gas removal capacity,
but the salt remains in the solution.
Excessive amounts of a strong base can damage or destroy the iron
sulfide scale protecting the metal as shown in Equation 10.29 and
Equation 10.30. This will result in a high solids content in the
solution, but usually the damage or destruction requires a period of
several weeks to months.
Most data indicate that neutralization of HSAS with a strong base
reduced corrosion, but at least one example of increased corrosive
attack of stainless steel is reported.
HSAS concentrations can be measured by titration or ion
chromatography, which is used to directly measure each acid. The
titration method does not report the amount of HSAS neutralized by
a strong base. Ion chromatography measures the concentration of
each anion that allows for improved troubleshooting should the rate
of HSAS formation increase dramatically. Ion chromatography
reports the neutralized acids and HSAS.
Excessive stripping of the acid gas can result in high corrosion rates
and removes the acid gas to very low levels. The hot lean amine
may contain too little H2S to keep the protective iron sulfide scale
intact. The exposed metal can be aggressively attacked by other
acids in the solution. Excessive stripping and corrosion in the hot
lean amine piping is more common with MDEA than other amines.
Corrosion in regenerator overhead systems is caused by CO2, H2S,
and other acids dissolved in the condensing steam. Ammonia and a
low concentration of amine are normally present in the overhead,
keeping the pH from dropping too low. Large concentrations of
ammonium bisulfide (Equation 10.31) can accumulate in the
overhead condensate, producing many of the problems found in
hydrotreater reactor effluent. Purging the reflux is a common
practice to remove ammonia and some of the acidic species.
10.6 Amine Degradation
Degradation of alkanolamines occurs as the result of exposure to
high temperatures and compounds, such as oxygen and carbon
monoxide.
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Oxygen-formed degradation products include organic acids like
formic acid and oxalic acid.
MEA, DIPA, DGA, and DEA also form chemical degradation
products in systems containing carbonyl sulfide (COS), carbon
disulfide (CS2), and CO2. CO2 degradation of DEA is well
documented and will not be repeated here. Many of these
degradation products are chelation agents that may be strong enough
to chemically remove iron from iron oxide or iron sulfide scales and
perhaps directly from the base metal.
10.7 Cracking Phenomena
Cracking of carbon steel components of amine units is due to two
primary phenomena:
•
Alkaline stress corrosion cracking (SCC)
•
Wet H2S cracking.
The term wet H2S cracking is used here to describe a number of
cracking and blistering mechanisms caused by hydrogen entry into
the steel, such as hydrogen induced cracking (HIC), sulfide stress
corrosion cracking (SSC), stress oriented hydrogen induced
cracking (SOHIC), and hydrogen blistering.
The use of clean steel and more extensive use of post weld heat
treatment (PWHT) have become the most common practices to
reduce the incidences of wet H2S cracking. Since hydrogen entry is
caused by corrosion, anything that can be done to reduce corrosion
will reduce wet H2S cracking. Alkaline stress corrosion cracking
(SCC) is controlled by PWHT and avoiding exposure of
inappropriate alloys to a specific environment.
In general, MEA can crack steel under milder conditions (lower
temperatures) than DEA or MDEA. MEA has caused cracking
down to ambient temperatures. DEA has caused cracking down to
140F (60C). DEA and MDEA behave similarly in terms of SCC.
Non-stress relieved carbon steel in amine service is most likely to
crack in areas operating at the highest temperature levels. It can
occur rapidly and extensively at regenerator bottoms temperatures
(240F to 280F [115C to 138C]).
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Some refineries recommend stress relief of all pressure vessels in
MEA service, regardless of the operating temperature. Piping in
MEA service should be stress relieved if operating temperatures are
above 100F (37.8C). Intermittent service lines, such as the
regenerator pumpout line to the amine storage tank, should also be
considered.
10.8 Corrosion Inhibitors
As a general rule, corrosion inhibitors are not necessary to control
carbon steel corrosion in amine units. With a properly operated
amine unit, corrosion inhibitors provide few, if any, benefits and
may even cause problems of their own, such as foaming and fouling.
However, when used, corrosion inhibitors for amine units fall into
two basic categories:
•
Filming inhibitors
•
Passivating inhibitors.
Filming inhibitors are organic nitrogen compounds (or mixtures of
compounds) that attach themselves to metal surfaces, forming a
protective barrier film. Passivating inhibitors react with the metal
and local environment to form a protective scale.
Filming inhibitors used in amine units must be compatible with the
amine solution and process. Amine units are unique when compared
to most other processing units. The pH of the system ranges from
near neutral, pH 7, in the reboiler to between 11 to 12.5 at the top of
the absorber. Amine units will also cause a corrosion inhibitor to
cycle up as little opportunity exists for the product to leave the
system. Foaming can be a problem if the product is not correctly
formulated. Any inhibitor considered for amine unit service should
be tested at the supplier’s recommended dosage and at several times
the recommended dosage.
Filming inhibitors were first used over 20 years ago and some have
been patented for their special ability to protect amine systems from
corrosion without causing adverse effects, such as foaming.
Research has shown that some inhibitors are very effective in
producing more protective iron sulfide scales. Filming inhibitors
may also act as dispersants to existing deposits in the system. A
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rapid increase in solution solids content may occur after initial
injection of one of these products and cause severe foaming.
Inhibitor injection location varies from unit to unit, but injection
into the regenerator overhead with a slipstream of reflux is common.
Filming inhibitors have low volatility and must be injected at that
location to protect the overhead system. Alternatively, a small
amount of concentrated amine solution can be injected to prevent
acid corrosion in the overhead system. In other units, a waterdispersible filming inhibitor is added directly to the circulating
amine solution. Inhibitor feed rate and concentration should be
determined by monitoring corrosion activity.
Passivating inhibitors rely on the formation of a protective scale
formed insitu on the metal surface. Older formulations included
sodium metavanadate and compounds of arsenic, tin, and bismuth.
These inhibitors should be used in systems processing only H2S or
CO2. However, environmental problems associated with these
inhibitors have nearly eliminated their use.
Newer formulations utilize oxygen scavengers to aid in the
formation of magnetite (Fe3O4). Magnetite scales can be very
protective if formed under the proper conditions. Under other
conditions, such as at too low a temperature, the magnetite formed is
not protective. Repeated formation and spalling of the scale results
in increased corrosion rates.
Oxygen scavengers, and passivators in general, do not form
protective scales at temperatures lower than 225F to 240F (107C
to 115C). The magnetite scale also must compete with the
formation of iron sulfide and iron carbonate scale. Galvanic attack
has been reported at the boundaries between the different types of
scale. Oxygen scavengers are occasionally used to remove oxygen
that can react to form organic acids, thiosulfates, or sulfates.
10.9 Materials of Construction
Carbon steel is the most prevalent alloy used in construction of
amine units. Carbon steel has provided good service in many units
and failed quickly in others. Carbon steel remains the alloy of
choice for exchanger shells, vessels, and most exchanger bundles
and piping. Tower trays, packing, and fasteners are usually made of
type 410, 304, or 316 stainless steel, but occasionally polypropylene
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or ceramic packing is used. Pumps utilizing cast iron housings and
type 316 or 317 stainless steel impellers are most commonly
specified. Flow control equipment is usually in cast iron bodies
with internals of type 316 stainless steel or 17-4PH.
Reboiler bundles of carbon steel are common, but type 316 and 304
stainless steel are increasingly prevalent. Lean/rich cross
exchangers are usually type 304 or type 316 stainless steel, but
carbon steel was more prevalent just a few years ago. Lean amine
coolers are usually carbon steel. Stripper overhead condensers are
usually carbon steel, but stainless steel and titanium have also been
used.
To minimize the danger of cracking, vessels should be fabricated
from clean steels and properly post weld heat-treated. Alternatively,
carbon steel vessels, weld overlayed with type 316 L or internally
clad with type 316L stainless steel, may be used.
10.10 Corrosion Monitoring
Corrosion has been successfully monitored with corrosion coupons,
electrical resistance probes, linear polarization probes, hydrogen
finger and patch probes, and other methods. Corrosion coupons
should be used to insure that electrical resistance or linear
polarization probes are working properly.
Corrosion coupons or insertion-type probes are typically used to
monitor corrosion in the hot areas of the unit, such as the:
•
Reboiler feed line
•
Hot lean amine piping
•
Hot rich amine piping
•
Stripper overhead condenser.
Amine solution analysis has been used to monitor metals
concentrations, but is not considered reliable. Even a minor unit
upset can dramatically increase or decrease the amount of soluble or
insoluble iron present in the amine solution on any given day.
Moreover, the sample of amine solution should be completely
acidified to insure the attainment of a good iron analysis. Sampling
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Amine Treating Units
technique and frequency may limit the usefulness of amine analysis
as a corrosion monitoring tool.
10.11 Corrosion Control Measures
Proper operation of an amine unit is the most effective method to
control corrosion. The key variables, which contribute to corrosion,
include:
•
Temperature
•
Differential pressure
•
Acid gas loading
•
HSAS concentration
•
Amine concentration
•
Solution velocity
•
Heat flux.
Corrosion is decreased by the following measures:
1. Adequate feed preparation is one of the most effective
methods of reducing amine contamination and corrosion. An
inlet separator can be used to remove entrained water from
the inlet gas. Injecting water upstream to the separator allows
for many of the HSAS forming acids to be removed from the
feed. Liquid feed often contains more acidic species than gas
feed. A water wash injected prior to the inlet separator
should use the best quality water available. Adding caustic to
the water wash will increase the removal of strong acids. The
use of sour water as the water source may increase the acid
concentration in the feed gas. Stripped sour water is often not
of acceptable quality.
2. The temperature of the amine solution should not exceed
260F (127C). Reboiler bulk temperatures in excess of
265F (129C) can result in aggressive corrosion and thermal
degradation of the amine. Steam pressures in excess of 65
psia saturated can result in high metal surface temperatures
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and corrosion. The steam control valve should be on the
steam inlet to allow the condensate to drain continuously
from the tubes. Temperatures above about 210F to 220F
(99C to 104C) in the rich amine can result in acid gas flashing and severe localized corrosion.
3. The reboiler steam rate should be operated to maintain a
regenerator top temperature adjusted for variable overhead
pressure. Excessive steam rates accelerate weak acid corrosion in the reboiler and lean piping and also increase velocities in the regenerator. Insufficient steam rates also increase
corrosion because higher acid gas concentrations reach the
regenerator bottoms and reboiler. Many control systems target a regenerator top temperature without correction for
changing pressure. Manual adjustments can be made by
using a reflux ratio graph.
Reboiler tubes should be laid out on a square pitch rather than
triangular pitch pattern to promote vapor disengagement. In
some cases, tubes may have to be removed to achieve the
same purpose.
4. Local pressure changes must be minimized by design and
operation. The net positive suction head to pumps must
include a large margin of safety to prevent acid gas flashing.
Piping should be designed to minimize turbulence. Areas
that must be exposed to large pressure changes should be
made of stainless steel, preferably type 316 or better.
5. The optimal combination of amine concentration, circulation
rate, and acid gas loadings should be used to minimize corrosion. Corrosion will generally be lower if amine concentration is increased prior to increasing rich loading or the
circulation rate. Rich amine acid gas loadings should be controlled to make product specification and to control corrosion. Increasing circulation rate increases velocity, local
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pressure changes, and steam requirements. Major problems
occur when the unit is at maximum amine concentration, circulation rate, and rich loading. Corrosion inhibitors may
allow continued operation in these situations with acceptable
corrosion rates.
6. Solids should be removed from the system by particulate filtration. Filter pore sizes of 10 microns to 20 microns are generally specified. Total flow filtration is required on some
units to maintain the solution in good condition. Rich filtration has the potential to be much more effective than lean
amine filtration. Filters should be changed based on differential pressure, but the system should be designed to last about
2 weeks. Systems requiring filter changes more frequently
may benefit from corrosion inhibitors.
7. Carbon filtration removes hydrocarbons from the amine solution. Hydrocarbons cause foaming that may contribute to
fouling. Carbon filtration is ineffective in removing HSAS.
8. Oxygen entry into the system should be eliminated. Makeup
water should be routinely tested to confirm the absence of
oxygen. Amine storage and sump tanks should be protected
from oxygen entry. The entrance of oxygen into upstream
processes may need to be investigated and corrected.
9. HSAS should be controlled to a concentration that is economically acceptable, balancing removal costs with equipment
costs. Corrosion rates and acid gas removal performance
should be monitored in determining the acceptable concentration of HSAS.
10. MEA, DIPA, and DGA systems should utilize the reclaiming equipment on a continual basis. Other amines can be
reclaimed or purged by a number of methods. Caustic addi-
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tion into the amine solution will restore the acid gas treating
capacity, but increase the salt and ash content.
11. Corrosion inhibitors can be used to reduce many corrosion
and fouling problems if used and monitored correctly. Inhibitor selection should include screening for compatibility with
the amine solution.
12. Fabrication methods should include PWHT in all locations.
Alloy selection should stress clean steels and welding practices. Stainless steels should be considered for areas of high
heat transfer, velocity, and pressure changes. Trays or packing should be made of stainless steel.
13. Operation of upstream equipment should be routinely
reviewed to minimize the introduction of strong acids to the
system. Changes in crude overhead water washes can
increase or decrease the amount of organic acids in the fuel
gas feed. Changes in fluid catalytic cracking catalyst circulation can alter the amount of CO2 and other acids in the fluid
catalytic cracking off gas.
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Sulfur Recovery Units
11-1
Chapter 11:Sulfur Recovery Units
Objectives
Upon completing this chapter, you will be able to do the following:
•
Describe the sulfur recovery process and identify when it is used
•
Identify the major types of sulfur recovery units, differentiating
among them
•
Identify and discuss the three major types of corrosion which
threaten sulfur recovery units
•
Describe, in general terms, the flow plan for a Claus reactor unit
and areas particularly vulnerable to corrosion
•
Recommend possible steps to prevent or mitigate corrosion for a
Claus unit and inspection steps to assure the mitigation is effective
•
Describe, similarly, the design of a cold bed adsorption (CBA)
unit, and identify the areas prone to corrosion
•
Discuss mitigation techniques or materials for CBA units and
inspection considerations
•
Discuss tail gas treating, when it is used, construction considerations, and areas prone to corrosion
•
Identify any corrosion mitigation steps which are unique to tail
gas treating and the inspection techniques that are best suited for
this type unit
•
Discuss, in general terms, the flow plan of an incineration unit,
how it works, and corrosion concerns applicable to this area
•
Describe any particular materials selection issues for incineration units and recommend inspection techniques for these sites.
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11.1 Introduction
A sulfur recovery unit (SRU) removes sulfur compounds from the
acid gas process streams before they are vented to the atmosphere.
The most common types of SRUs are:
•
Claus units
•
Cold bed adsorption (CBA) units
•
Tail gas treating units
•
Incineration units.
The particular SRU or combination of units used depends on
composition of the acid gas feed and the degree of sulfur removal
required before the gases are vented to the atmosphere.
The remainder of this chapter will describe the process within a
basic SRU, then describe the three most prevalent corrosion
problems encountered in these units. We will then look specifically
at how corrosion impacts a Claus processing unit, a cold bed
adsorption unit, a tail gas treating unit, and an incinerator system
and examine corrosion mitigation techniques for each.
11.2 Sulfur Recovery Units
Sulfur recovery units (SRUs) remove sulfur compounds (mainly
H2S) from gases produced by the sweeting of refinery gases or sour
field gases. The sulfur compounds are converted to elemental sulfur,
and the sulfur is condensed to a liquid state for removal. Any sulfur
compounds remaining in the stream are oxidized in the incinerator
to sulfur dioxide (SO2) before release to the atmosphere.
The feed will likely contain mainly hydrogen sulfide (H2S), with
limited carbon dioxide (CO2) and cyanide (HCN). The feed gas
most commonly comes from amine regenerators and sour water
strippers located in various refinery units and is considered an acid
gas because the components will form acids when in the presence of
liquid water.
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11.2.1 Sulfur Chemical Reactions
SRUs have very complicated sulfur chemical reactions, resulting in
many sulfur species existing at any one condition or process step.
The overall combustion reaction in the reaction furnace is the Claus
reaction in which one-third (1/3) of the H2S is converted to SO2.
The catalyst beds convert most of the remaining H2S and SO2 to
elemental sulfur. The basic chemical reactions follow:
H2S + 3/2O2  SO2 + H2O and 2 H2S + SO2  3S+ 2H2O
Figure 11.1 depicts a typical Claus reactor unit and the sulfur
recovery process.
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Figure 11.1 Flow Diagram for Claus Reactor Unit
11.2.2 Sulfur Recovery Process
The sulfur recovery process begins as the acid feed enters the Claus
unit at low pressure (less than 15 psig), and a knockout vessel is
used to remove condensed and entrained liquids (mostly water,
some hydrocarbons, and amine if from an amine stripper). In the
reaction furnace, where temperatures range from 1800F to 2800ºF
(982C to 1538C), the acid gas is combusted with air in a reducing
atmosphere.
Combustion gases are cooled to 400ºF to 450ºF (204C to 232C) as
they pass through steam-generating shell and tube exchangers. Most
of the elemental sulfur formed during combustion is condensed,
separated, and drained to storage at this point.
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The process stream is reheated and passed through the first catalyst
bed where additional sulfur is formed. The process gas is again
cooled and sulfur condensed, separated, and forwarded to storage.
Two or three catalyst beds are typical in a Claus reactor unit, with
condensation occurring after each bed. To remove as much sulfur as
possible from the process gas, the final condenser outlet temperature
is typically less than 300ºF (149C).
11.2.3 Tail Gas Treating Unit
The remaining sulfur compounds in the process gas leaving the
Claus unit are typically reduced further in the tail gas unit before
venting the stream to the atmosphere.
There are several designs for tail gas units. A typical unit, depicted
in Figure 11.1, uses a combustion burner, operating in a reducing
atmosphere. A mixing chamber reheats the process gas to conditions
suitable for the catalyst bed reaction. Other designs use a heat
exchanger and a hydrogen stream instead of the burner and mixing
chamber.
The tail gas catalyst bed converts the remaining sulfur compounds
to H2S, with the process gas then cooled in an exchanger and water
quenched in a direct contact tower. See Figure 11.2.
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Figure 11.2 Tail Gas Unit, Amine Adsorption System, and Incinerator
The H2S is removed from the process gas with an amine adsorption
system and recycled to the front of the Claus unit. Remaining
process gas is forwarded to the incinerator.
11.2.4 Incinerator
The incinerator heats the process gas to 1200ºF to 1500ºF (648C to
816C), using a fuel fired burner in an oxidizing atmosphere. Any
remaining H2S is converted to SO2 and released to the atmosphere.
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In some incinerator units, a waste heat recovery boiler is used. In
these applications, the process gas is usually cooled to 500ºF
(260C) to recover heat. The process gas is not allowed to reach the
condensing temperature for water mixed with sulfur oxides to
prevent sulfur acid formation.
11.2.5 Cold Bed Adsorption (CBA) Unit
CBA units offer greater efficiency in sulfur removal than do Claus
units. A CBA unit may be combined with an incinerator unit to
provide adequate sulfur removal in some instances.
The CBA process uses the same reaction furnace and first catalyst
bed as in a Claus unit. The CBA catalyst bed is operated at the dew
point for sulfur, and the sulfur is adsorbed into the catalyst bed. The
reaction in a CBA catalyst bed is essentially the same as that in a
Claus catalyst bed except the recovery is enhanced by the lower
operating temperature.
Two CBA catalyst beds are typically used, with one in removal
service and one in regeneration service. When the in-service bed has
accumulated significant sulfur, it is removed from service and
regenerated. The regenerating bed is then heated from the typical
260ºF (127C) adsorption temperature (during accumulation of
sulfur) to over 600ºF (315C) to remove the sulfur from the bed.
The sulfur is removed from the bed in liquid and vapor states. The
sulfur vapor is condensed in an exchanger, and the liquid sulfur is
forwarded to storage. The total cycle time for a CBA reactor
typically ranges from 24 to 48 hours.
11.3 Corrosion Mechanisms
The three most common corrosion problems in a SRU are:
•
Sulfidation of carbon steels, due to high temperature exposure to
H2 S
•
Sour environment corrosion, resulting in wet H2S cracking
•
Weak acids corrosion, due to acids formed from water condensation with sulfur compounds.
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11.3.1 Sulfidation of Carbon Steels
In a typical SRU, sulfidation (reaction of H2S with Fe) forms an iron
sulfide (FeS) scale. This scale is semi-permeable, often flaky, and
offers minimal resistance to further scale formation. The FeS scale
created by sulfidation is pyrophoric and will ignite spontaneously
when exposed to air. Furthermore, the FeS scale will crack and flake
when exposed to temperature changes of 200ºF (93C) or when
exposed to a high stress, which nears or exceeds the yield of the
material. The cracking and flaking of the scale increases the
corrosion rate.
The sulfidation reaction is dependent on H2S concentration and
temperature. Typical SRU piping and equipment operate at metal
temperatures up to 650ºF (343C), at which the sulfidation corrosion
rate for carbon steels can be accommodated by a 1/8-inch corrosion
allowance (for a 20-year design life).
The Couper-Gorman curves (presented in Chapter 7,
Hydroprocessing Units) are intended for pressures considerably
higher than the operating pressure of a SRU. Little information is
available for conditions at near atmospheric pressure. In many
cases, the curves are thought to be 50ºF to 100ºF (10C to 37.8C)
on the conservative side, when applied to typical SRU process
conditions. In critical areas, such as the tube sheet of the waste heat
exchanger after the Claus reaction furnace, it is suggested that metal
temperature be limited to approximately 600ºF (315C).
11.3.2 Sour Environment Corrosion
The presence of H2S and water is considered a sour environment,
which often leads to wet H2S corrosion damage. Sour environment
corrosion produces hydrogen charging of carbon steel and the
associated hydrogen induced cracking (HIC). In addition to HIC,
the corrosion of carbon steels by a sour environment can result in
damage mechanisms, such as hydrogen blistering, sulfide stress
cracking (SSC), and stress oriented hydrogen induced cracking
(SOHIC).
Additional information on these corrosion mechanisms can be found
in the following NACE publications, which are presented in the
current editions of Appendix J, Appendix A, Appendix I, and
Appendix G, respectively:
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•
NACE Publication 8X294, “Review of Published Literature on
Wet H2S Cracking of Steels Through 1989,” Houston, TX:
NACE, 1994.
•
NACE Publication MRO103, “Materials Resistant to Sulfide
Stress Corrosion Cracking in Corrosive Petroleum Environments,” Houston, TX: NACE.
•
NACE Publication 8X194, “Materials and Fabrication Practices
for New Pressure Vessels to be Used in Wet H2S Refinery Environments,” Houston, TX: NACE, 1994.
•
NACE Publication SP0472, “Methods and Controls to Prevent
In-Service Environmental Cracking of Carbon Steel Weldments
in Corrosive Petroleum Refining Environments,” Houston, TX:
NACE.
The inlet acid gas line and associated knockout drum are the only
areas usually at risk for sour environment damage during normal
operation of the SRU.
11.3.3 Weak Acid Corrosion
Absorption of sulfur compounds, such as H2S, SO2, and SO3, into a
condensed water phase forms a sour environment of sulfur acid.
Operating pressures, generally less than 15 psig, and resulting
constituent partial pressure in a SRU are low enough to produce
only weak acids.
Metal surfaces that are allowed to cool near the condensation
temperature during normal operation, shutdown, or startup
operations will produce these weak acids. Accordingly, it is
necessary to limit the time that the acids may exist.
A less than 1% sulfuric acid vapor condition has the ability to
produce an 85% sulfuric acid in the water phase. Even weak acids
will significantly corrode carbon steels in an SRU.
Weak acids do not usually affect austenitic stainless steels, unless
they are sensitized. Sensitization of austenitic stainless steel may
occur in the 600ºF to 1200ºF (315C to 648C) temperature range,
when there is sufficient carbon migration to the grain boundaries.
This migration causes the carbon to combine with chrome, reducing
the chrome content at the grain boundary. Typically, most areas of
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an SRU will have operating temperatures within the sensitization
range for 300-series austenitic stainless steels.
At times, some areas of an SRU will have operating temperatures
high enough to cause the austenitic and high-nickel alloy materials
to develop reduced ambient temperature ductility during shutdowns.
The reduction in ambient temperature ductility may be caused by
mechanisms affecting grain structure and phase, such as sigma
phase development.
Specific ductility reduction information for many higher alloys may
only be available from the manufacturer. A designer of an SRU
must consider this reduction in ductility when selecting materials
that may be stressed or subjected to impacts at ambient conditions.
11.4 Corrosion of Claus Units by System
Corrosion of the Claus unit can occur in the following systems:
•
The feed gas system
•
The reaction furnace and waste heat exchanger system
•
Claus reactors, condensers, and reheat system
•
Liquid sulfur rundown lines and storage system.
Each system will be examined by addressing specific corrosion
concerns for each, ways of mitigating the corrosion, and issues
pertaining to inspections.
11.4.1 Feed Gas System
The feed gas system is composed of the acid gas piping into the unit
and the associated knockout drum used to remove most of the free
liquids. Carbon steel is commonly used to construct the feed gas
system. Valves are usually specified as cast steel bodies with
stainless steel trim and Teflon or butyl seal materials.
11.4.1.1 Corrosion Concerns
The feed gas is usually rich in H2S and is saturated with water
vapor, resulting in the formation of weak acids. It may also contain
entrained hydrocarbons and amines. Hydrogen charging can result
from these service conditions and, therefore, the feed gas system is
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considered at risk for HIC (including hydrogen blistering) and SSC.
In addition, ammonia may be present in the feed gas, leading to
alkaline related stress corrosion cracking. If cyanide is present as
well, it will increase the corrosion rate and resulting hydrogen
charging.
11.4.2 Mitigation of Corrosion
Gas piping should be designed to avoid accumulation of liquids to
prevent production of weak acids. Piping for sour water stripper gas
is normally insulated and traced in all climates if the gas contains
appreciable amounts of ammonia, which can form ammonia salts at
low temperatures. Small diameter piping is usually seamless to
prevent hydrogen blistering and stress oriented cracking. Large
diameter pipe is fabricated from plate materials, which may increase
the risk of damage from both hydrogen blistering and stress oriented
cracking. Controlling weld hardness through postweld heat
treatment (PWHT) of welds or by using special weld procedures as
well as using carbon-equivalent controlled steel can mitigate SSC in
the gas piping.
The knockout vessel is typically made of carbon steel and has a
maintained liquid level, which raises concerns for hydrogen
charging accompanied by the risk of sour environment damage.
PWHT is the most common technique used in the knockout vessel
to reduce the risk of SSC. HIC-resistant steels can be used to
control hydrogen blistering.
11.4.2.1 Inspections of the Feed Gas System
Inspections of the feed gas system involve standard procedures for
piping, with the addition of hardness verification of production
welds. Utilizing a one-sided manual metal arc welding procedure
without the
use of PWHT can provide piping weld hardness control. For other
welding processes, a Vickers micro-hardness verification procedure
with value requirements per the recommendations of NACE SP0472
(current edition) is also recommended. (See Appendix G.)
Vessel fabrication is monitored as with any typical vessel. Welding
procedures should include adequate hardness controls, including
PWHT. The interior of the vessel is commonly given a Wet
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Magnetic Particle examination, which is documented to assist with
future inspections.
Standard in-service inspections are performed, with additional
attention given to water accumulation and gas liquid interface areas.
Appendix H, NACE Publication RP0296 (current edition),
“Guidelines for Detection, Repair, and Mitigation of Cracking of
Existing Petroleum Refinery Pressure Vessels in Wet H2S
Environments,” (Houston, TX., NACE) provides additional
information regarding inspection for this type of damage.
11.4.3 Reaction Furnace and Waste Heat
Exchanger Systems
The reaction furnace system includes the burner assembly and
reaction furnace chamber. The burner air plenum and mounting are
typically carbon steel. Stainless steel and refractory materials are
used in flame and radiation exposure areas. Acid gas is usually
considered dry at the entrance to the burner due to heating from the
burner.
The reaction furnace chamber is usually carbon steel with refractory
lining. The waste heat exchanger is usually a carbon steel fire tube
steam generating design, with a refractory covered tube sheet
utilizing ceramic or alumina ferrules.
11.4.3.1 Corrosion Concerns
Corrosion concerns in the reaction furnace and waste heat
exchanger system are sulfidation of steel and alloys due to hightemperature exposure to H2S and weak acid corrosion. The weak
acids may condense during normal operation or shutdowns.
11.4.3.2 Mitigation of Corrosion
The parts of the burner that operate at less than 600ºF (315C) are
carbon steel. For the higher temperature burner parts, type 310
stainless steel is commonly used, but type 316 stainless steel and
higher nickel alloys may also be used. In addition, some burners
may be constructed of refractory or ceramic parts in higher
temperature locations.
The operating temperature in the furnace chamber is usually in the
range of 1800ºF to 2800ºF (982C to 1538C). Therefore, the
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furnace chamber is constructed of a carbon steel shell with a
refractory lining system. The refractory lining system is designed to
maintain the carbon steel shell above the weak acid condensing
temperature (250ºF [121C]) and below the steel sulfidation
temperature (650ºF [343C]).
Type 310 stainless steel refractory anchors are commonly used for
castable refractory installations. It is customary to require that the
refractory be high in alumina, free of elemental phosphorus, and of
low iron content to prevent these materials from reacting with the
process environment.
The exchanger is carbon steel on both the process and the steam
side. The refractory used on the tube sheet is similar to that used in
the furnace chamber. Exchanger steam pressure may vary from 50
psi to 700 psi, depending on the design details, such as type of reheating and utility requirements.
The design of the tube sheet refractory and ferrule system is critical
to protecting the exchanger tube sheet and tube inlet from damage
and must limit the heat flux and metal temperature to prevent
sulfidation. The refractory used on the tube sheet is similar to that
used in the furnace chamber. The ferrules are normally zirconium
silicate or high-alumina materials. Sodium silicate, commonly
referred to as water glass, should not be used in ferrule installation
because it may serve as a fluxing agent for some ferrule materials.
The remainder of the reaction furnace and waste heat exchanger
system that operates above 650ºF (343C) is usually carbon steel,
with refractory lining to protect from sulfidation. PWHT is not
usually used in this area unless required by the fabrication code
since normal operation is considered dry acid gas service, with
occasional exposure to weak acids.
11.4.3.3 Inspections in the Reaction Furnace and
Waste Heat Exchanger System
The inspections for carbon steel fabrications are usually limited to
those required by the governing fabrication code or agency.
Hardness or flaw inspection methods are normally not required.
Refractory suppliers’ recommendations for inspecting refractory
installation should be followed. Refractory installation inspections
should include verification of the material quality prior to
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installation and refractory installers’ work processes, such as those
required for gunned refractory installations.
In-service inspections for carbon steel are typically conducted
according to standard procedures. Inspection during operation
includes on-line ultrasonic thickness monitoring of areas suspected
to be susceptible to continuous weak acid corrosion and on-line
thermography to determine refractory condition.
During unit shutdown, refractory systems are usually inspected for
degradation. Changes in operating practices, such as hot standby
conditions or the rate of heating on startup, can significantly impact
refractory life. Some minor cracking is normal in ferrules used in
the waste heat exchanger tube sheet, and such cracks need not be a
cause for concern. Major cracks, spalling, or damage to the
refractory or ferrules should be repaired according to
manufacturers’ instructions.
11.4.4 Claus Reactors, Condensers, and
Reheat System
The Claus reactors, condensers, and reheat system are composed of
two or more catalyst beds and associated sulfur condensers and
various reheaters. The reactor vessels are commonly carbon steel,
horizontal vessels, with austenitic stainless steel catalyst support
systems and carbon steel support beams.
The condensers are usually carbon steel, with cooling provided by
generating steam on the shell side of the exchanger. The final
condenser in the train operates at the coldest temperatures to remove
the most sulfur from the process stream.
Reheaters range from hot-gas bypass, steam-heated shell and tube
exchangers to direct and indirect fired types. The usual construction
materials for these are carbon steel, with certain alloys used for
some of the fired reheaters.
Refractory linings are typically used in the reactor vessels, due to
concerns for sulfur fires in the reactors if oxygen should enter a hot
catalyst bed. Beds normally contain appreciable amounts of liquid
sulfur and sulfur in the catalyst pores.
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11.4.4.1 Corrosion Concerns
Corrosion concerns in the Claus reactors, condensers, and reheat
system are related to reactor outlet and condenser inlet carbon steel
exposure to high temperatures near the sulfidation range, continuous
exposure to weak acids, and sensitization and polythionic acid stress
corrosion cracking of austenitic stainless steels.
11.4.4.2 Mitigation of Corrosion
PWHT of carbon steel materials is not normally required in these
areas since normal operation is considered dry acid gas service. The
exposure to temperatures high enough to cause sulfidation of carbon
steels is normally avoided during normal operating conditions.
However, some units fire the reaction furnace burner on fuel gas
with a small amount of excess oxygen during a plant shutdown to
remove sulfur from the catalyst bed, resulting in increased potential
for sulfidation of the steel parts.
Refractory is commonly used to protect steel parts, including the
catalyst bed vessels. Where refractory is used, it may be necessary
to use an external shroud or insulation system to maintain the metal
above the acid condensation temperature. The catalyst support
system is also subject to process gas temperatures and requires the
same consideration. Refractory covering of carbon steel support
beams, similar to fireproofing, is used for short-term fire protection
for the support beams during the use of oxygen in the catalyst beds
during shutdown.
Oxygen is a danger to both hot (or warm) and cold units. Hot units
are vulnerable to sulfur fires, which are mitigated usually by using
refractory linings. Oxygen introduced into a cold unit, as during
shutdown or inspection activity, can cause pyrophoric reaction with
FeS scale throughout the unit. Also, atmospheric air contains
enough moisture to cause polythionic acid corrosion attack on
sensitized austenitic stainless steels. In addition, oxygen entering a
cold plant during startup may produce SO3, which results in strong
sulfuric acid corrosion.
11.4.4.3 Inspections in the Claus Reactors,
Condensers, and Reheat System
Inspections commonly used in this service are the same as for
previous sections. The outlet channel of condensers, particularly the
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final condenser, are areas that may be subjected to increased weak
acid corrosion on startup, shutdown, and normal operation. These
areas should be inspected for corrosion of the channel and for tube
wall thinning.
If the catalyst bed outlet temperature exceeds 650ºF (343C), carbon
steel materials should be inspected for sulfidation.
11.4.5 Liquid Sulfur Rundown Lines and
Storage System
The sulfur rundown lines are usually carbon steel with external
steam jacketing to maintain the sulfur in a molten state. The sulfur
storage system is a concrete pit, which is fully enclosed and has
steam coils to maintain the sulfur temperature. Pumps, which are
usually the sump pump type with carbon steel construction, are used
to transfer the sulfur from the pit.
11.4.5.1 Corrosion Concerns
Corrosion concerns for sulfur rundown lines and storage areas are
connected to low concentrations of H2S contained in the molten
sulfur. The temperatures are not high enough to cause sulfidation,
but weak acid formation may occur. The formation of FeS can also
occur wherever H2S is exposed to carbon steel.
11.4.5.2 Mitigation of Corrosion
Rundown lines and the sulfur seals will not be subjected to weak
acid corrosion unless water vapor enters the system and condenses.
Air can enter the system through site ports and look boxes. The
volume of air ingress is normally low and a corrosion allowance of
1/8 in. for general weak acid corrosion is customary.
Positive air venting can prevent an explosive mixture of H2S from
building up in the pit. The sulfur pit is usually purged with
atmospheric air or an inert gas, such as nitrogen.
The pit concrete is an acid-resistant type IV concrete. The pit cover
is constructed of either concrete or aluminum, which offers good
corrosion resistance to weak acids. The steam coils placed in the pit
may be carbon steel in the liquid sulfur area, but carbon steel will be
vulnerable to weak acid corrosion at the sulfur liquid and air
interface. The use of type 316 stainless steel to extend the coils from
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the minimum liquid level through the pit top is suitable for most
services. In areas where type 316 materials are known to be
unsuitable, alloy 20 has been an effective substitute.
The sulfur pump is constructed of carbon steel with a ductile iron
impeller, having an austenitic stainless steel shaft and carbon shaft
bushings. The pump column is steam jacketed and subject to weak
acid corrosion, but carbon steel is used for most services. Type 316
stainless steel may be specified for more severe service.
11.4.5.3 Inspections in Liquid Sulfur Rundown Lines
and Storage System
Inspections used in this service are the same as those addressed in
previous sections. However, inspection of the pit area is difficult, as
the pit must be emptied to accommodate access. Partial inspections
can be accomplished with specialized remote viewing equipment.
The deterioration of the pit concrete is usually most prevalent in the
vapor space, and this area should be inspected on a routine basis.
11.5 Corrosion of CBA Units
Corrosion of the cold bed adsorption unit can occur in the CBA
reactors, condensers, and piping.
The CBA system is similar to systems described in the Claus unit,
including materials of construction, except that two reactors with
their associated condensers and piping are operated in a temperature
cycle. The temperature cycle is usually of 24 to 48 hours in duration.
About 1/3 of the regeneration time is in the heating mode, 1/3 of the
time in the bed-hold phase, and 1/3 of the time in the cooling mode.
11.5.0.1 Corrosion Concerns
Corrosion concerns for CBA units involve the same sulfidation and
weak acid corrosion considerations as in the Claus unit. Additional
concerns stem from the variations of temperature as the unit goes
through a complete cycle. Cyclic temperature changes may lead to
FeS scale cracking.
The cracking of the FeS scale is not severe, and the scale will reestablish with each cycle. The cracking and re-establishing of the
FeS scale increases the corrosion rate to 150% of a non-cyclic
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equivalent temperature application. In addition, corrosion rates may
increase significantly if the carbon steel base materials are cyclicstressed near the yield, due to the corresponding material strain.
Weld areas of mitered fittings and other stress concentrating
contours may also develop stresses in the yield range or greater.
11.5.0.2 Mitigation of Corrosion
Reactor vessels and exchanger channels, which are subject to cyclic
temperature changes, are aluminized to reduce FeS scale formation.
Piping may be aluminized as well, depending on the maintenance
and capital cost criteria of the refiner. Aluminum thermal spray
coating techniques are used for all large equipment surfaces exposed
to the process stream. Diffusion coatings are used to protect smaller
items and items that are difficult to coat with thermal spray
applications, such as small equipment and piping nozzles.
Thermal spray aluminum coatings may require repair and renewal
during the life of the unit, particularly in areas of high stress/strain,
such as mitered piping elbows. These areas can be expected to
cause additional damage to the FeS layer with each temperature
cycle and may display coating damage or increased corrosion rates
of base carbon steel materials, with failures reported within 3 to 5
years of operation.
When designing areas susceptible to high stress/strain, it is
recommended to maintain localized stresses to significantly less
than the yield of the material. Sensitized austenitic stainless steels
may be used in situations where bare and coated carbon steel
materials have performed unsatisfactorily.
11.5.0.3 Inspection of CBA Reactors, Condensers,
and Piping
The fabrication inspections for this equipment and piping are similar
to those for the Claus unit. The application inspection for the
thermal spray coating is important. The control of atmospheric
conditions, such as dew point, humidity, and temperature, is
necessary for an optimal coating application. Aluminization by
diffusion is conducted in high-temperature retorts. Inspection for
diffusion depth and dimensional changes to the base materials is
considered necessary.
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In-service inspections are similar to those for the Claus unit, with
particular attention paid to repair and renewal of thermal spray
aluminum. Inspection of the thermal spray aluminum coating
requires internal access and visual observation. The coating is
considered serviceable unless flaking or complete loss of coating
has occurred. Destructive testing of the coating is not considered
necessary or practical.
11.6 Corrosion of Tail Gas Treating Units
Corrosion of the tail gas treating unit can occur in the:
•
Burner and mixing chamber
•
Tail gas reactor and waste heat exchanger
•
Water quench and recirculation blower system
•
H2S adsorption system.
11.6.1 Burner and Mixing Chamber
The tail gas unit uses a burner and mixing chamber to heat the Claus
tail gas before entering the hydrogenation reactor catalyst bed.
The system has very similar materials of construction, corrosion
concerns, corrosion mitigation techniques, and inspection
requirements as those of the Claus burner and reaction furnace. The
process gas enters the mixing chamber and combines with flue gases
from the burner. The temperature range of the process gas leaving
the mixing chamber is approximately 550ºF to 725ºF (288C to
385C). The piping to the reactor vessel is customarily refractorylined carbon steel.
11.6.2 Tail Gas Reactor and Waste Heat
Exchanger
The hydrogenation catalyst bed reactor is customarily a carbon steel
vessel with refractory lining. The reactor vessel is similar to the
Claus reactor vessel, built of carbon steel with austenitic stainless
steel catalyst support systems and carbon steel support beams.
However, the reactor vessel is not lined with refractory since sulfur
fires are not a concern. The waste heat exchanger has the same
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Sulfur Recovery Units
design considerations as described for the Claus unit. It is usually a
carbon steel fire tube steam generating design with a refractory
covered tube sheet utilizing ceramic or alumina ferrules.
Corrosion concerns are also essentially the same as described for
comparable segments of the Claus unit—weak acid corrosion and
sulfidation of the steel and alloys due to high-temperature exposure
to H2S.
Due to slightly higher operating temperature in the tail gas unit, it is
customary to use an internal refractory lining and a very thin layer
of insulation or special lagging on external surfaces. These materials
are required to maintain the reactor carbon steel shell temperature
above the acid condensation temperature while not allowing the
carbon steel to reach a temperature high enough to develop
sulfidation.
The catalyst support is usually an austenitic stainless steel, with
carbon steel or austenitic stainless steel used for support beams. It is
customary to control the amount of oxygen in the circulating gas
stream to oxidize the catalyst prior to opening the system for
maintenance or inspection. Inspection requirements are similar to
those for the Claus reactor and waste heat exchanger.
11.6.3 Water Quench and Recirculation
Blower System
The water quench system consists of a direct contact tower, a water
pump-around loop, and a cooler. Most systems use a recirculation
blower to recycle quenched process gas to the mixing chamber
during unit startup. Some units operate the blower continuously
during normal or turndown operations. Carbon steel is primarily
used to fabricate equipment and piping in this system. A 1/8-inch
corrosion allowance is typical for carbon steel materials in the
pump-around loop. The recirculation blower that is used for startup
service only is usually cast iron or steel with an internal coating and
aluminum impeller. A continuously operating blower will usually be
constructed of austenitic stainless steel.
The water quench and recirculation blower system is prone to weak
acid corrosion, resulting from direct contact of the process gas with
water as the process gas is cooled. The pH of the circulating water
must be controlled to remain in the range of 6.5 to 7.0 to avoid the
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development of a low-pH corrosion condition. On-stream pH
monitoring can be used to control the pH. The presence of oxygen in
the circulating water system can lower the system pH and generate
oxygen-related corrosion mechanisms that display extreme
corrosion rates. Blowers used only for startup service need to be
fully isolated from the process stream, completely purged, and
provided with a continuous purge of an inert gas, such as nitrogen.
Inspection procedures for the water quench area are similar to those
for the Claus unit. Inspections will find the most corrosion in areas
exposed to the highest velocity, such as pump discharge piping.
11.6.4 H2S Adsorption System
The adsorption of H2S normally uses an amine system with the H2S
recycled to the acid gas feed to the Claus unit.
Overhead gas from the amine contactor tower flows to the
incinerator and contains CO2 with low concentrations of H2S
saturated with water vapor. The line is typically carbon steel and
designed to be self-draining. Heat tracing may be added to avoid
condensed liquid increasing corrosion and to prevent liquid from
entering the incinerator burner.
The overhead gas from the amine stripper tower flows to the front of
the Claus unit and contains CO2 with high levels of H2S saturated
with water vapor. This line, also, is typically carbon steel and
designed to be self-draining. Heat tracing may be added to avoid
the condensation of liquid, which can increase corrosion rates.
Inspection procedures are identical to those for Claus units.
11.7 Corrosion in the Incinerator System
Corrosion in the incinerator system can occur in the burner,
retention chamber, and stack system. The incinerator system
normally uses a fuel gas fired burner to heat the waste gas stream to
approximately 1200ºF to 1500ºF (648C to 816C). The heating
oxidizes any remaining H2S or SO2 prior to venting into the
atmosphere.
The burner is usually a naturally aspirated type, using a stack draft.
Some incinerators use a waste heat boiler to recover energy. These
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incinerators require an air blower to provide combustion air at
sufficient pressure to overcome the additional pressure drop of the
boiler.
The burner, mixing chamber, waste heat boiler, and stack are
customarily made of carbon steel. The corrosion concerns are
similar to those for the Claus unit. However, excess oxygen used in
the burner allows some SO3 to form. The presence of SO3 leads to
the condensation of sulfuric acid if the temperature drops below
250ºF to 300ºF (121C to 149C).
The use of refractory, insulation, and shroud designs protect the
incinerator system from sulfidation and acid condensation. The
1200ºF (648C) operating temperature requires the use of refractory
to protect the carbon steel. External insulation is primarily used in
applications where a waste heat boiler reduces the 1200F (648C)
operating temperature to 500F (260C). It is important that the
steam generation temperature be above the acid condensation
temperature. It is common practice to use a shroud or special stack
design to control metal temperatures for units without a waste heat
boiler.
Inspection techniques are similar to those for the Claus unit, with
reliance on thermography to evaluate the internal refractory lining
of the stack while in operation.
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Chapter 12:Refinery Injection
Systems
Objectives
Upon completing this chapter, you will be able to do the following:
•
Define injection point according to API 570, Piping Inspection
Code
•
Identify the components of an injection system
•
Identify factors influencing the design of a refinery injection system
•
Discuss good engineering practices that must be followed when
designing an injection system
•
Discuss injection system design in terms of achieving process
objectives
•
Discuss material selection considerations significant to the injection system design process
•
Describe the design of an inspection program for inspection
point locations
•
Discuss considerations that must be taken into account when
designing the location of the injection point
•
Discuss several injection system hardware design considerations
and solutions
•
Design an injection system for the injection of an oil-soluble,
film-forming corrosion inhibitor into an atmospheric crude
tower overhead system.
12.1 Introduction
Refinery injection locations are those sites where process additives,
wash water, or small hydrocarbon streams are combined with a
process stream. Proper design and use of injection systems are
necessary to maintain the reliability of the equipment and ensure
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optimum performance of refinery operations. There are many types
of refinery injection systems, but all have similar design
requirements and common elements. This chapter presents factors
to consider during the design and use of refinery injection systems.
12.2 Definitions
12.2.1 Injection Point
The American Petroleum Institute (API) defines an injection point
in API 570, Piping Inspection Code, as ”a location where relatively
small quantities of materials are injected into a process stream to
control chemistry or other process variables.”
In common practice, an injection location is any location where a
process additive, wash water, or other hydrocarbon stream is
injected into a much larger process stream to improve or maintain
the performance of the process.
12.2.2 Injection System
An injection system includes the injection point as defined by API
570 as well as all lines, valves, equipment, tanks, pumps, and meters
necessary to introduce the additive to the process stream.
12.3 Injection System Design
The specific design of a given refinery injection system is
influenced by several factors, including:
•
Properties of the treated stream
•
Properties of the additive
•
The refiner’s engineering standards and procedures
•
Access to the process stream.
Due to the variety and uniqueness of each application, the
information in this chapter is not intended to be used as a
recommendation for the design of injection systems. Rather, it is
offered as a guideline for those common elements that should be
considered when designing and implementing a refinery injection
system. Further guidance can be found in NACE Publication
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34101, “Refinery Injection and Process Mixing Points”, included as
Appendix R.
12.3.1 Injection System Design Parameters
The proper design and selection of hardware for chemical injection
systems are critical for the success of any refinery injection system
or chemical additive program. Generally, chemical injection
systems are applied to prevent undesired chemical or mechanical
reactions to process units or to impart desirable properties to a
process stream. A properly designed and implemented chemical
application system is key to the safe and economic operation of
process units and for the application of the injection facility.
Although the chemical supplier often maintains and monitors the
additive injection system, it is ultimately the responsibility of the
refiner to ensure the overall mechanical reliability of the chemical
injection system, as well as the safety of the personnel handling the
additive chemicals. Before beginning the design of a chemical
injection system, especially for a new application, the health and
safety requirements of the operating company must be considered.
It is the responsibility of the chemical supplier to ensure that the
refiner is well informed of all aspects relevant to the safe handling
and application of a chemical and to aid in the decision-making
process.
The chemical injection system design should address the following:
•
Engineering practices
•
Process design
•
Material selection considerations
•
Inspection of injection point locations
•
Location of injection point.
12.3.1.1 Engineering Practices
The first step in designing a refinery injection system is the use of
good engineering practices. Most refiners have documented
engineering standards and standard operating procedures (SOPs)
which are important for ensuring the integrity of the process. The
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refiner has an engineering review, sometimes referred to as a
Management of Change (MOC), which will employ these site
specific practices.
Information that should appear on the MOC that usually comes from
the supplier includes:
•
Material Safety Data Sheet (MSDS), with handling hazards outlined
•
Potential chemical incompatibilities
•
Potential material incapabilities
•
Purpose of additive injection
•
Recommended application rates
•
Additive stability relative to process conditions
•
Composition and flow rate of desired carrier streams
•
Plant utility requirements for equipment provided by the supplier
(electricity, air, water, etc.).
12.3.1.2 Process Design
The injection system should be designed to achieve the process
objectives. While this seems self-evident, it is critical to clearly
understand and document the purpose of the chemical addition as
well as the conditions under which the system will operate. The
entire system, including the injection point, the supply system,
instrumentation, and control, should be considered. Documentation
of the process design, anticipated operating conditions, materials of
construction, and the monitoring requirements is recommended.
In the design of the system, the potential for interaction between the
injected stream and the process stream should be considered.
Anticipate potential material degradation problems and choose
designs and materials of construction to achieve the desired
reliability. It is often the purpose of the injected stream to react
chemically with the process stream. The effect of these reactions
must be considered. The possibility of a phase change in the
additive stream should be part of the design consideration.
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Final design documentation must include system parameters for
normal operation and a training package for refinery personnel and
other operators of the injection system. For example, if the system
involves a chemical additive, the training must include:
•
All steps and precautions for chemical delivery
•
Procedures for measuring and regulating the chemical injection
rate
•
The maintenance of the injection equipment
•
The stated purpose of the additive.
12.3.1.3 Materials Selection Considerations
In the design of injection systems, it is important to consider the
materials of construction. Material selection is complicated by the
exposure of the injection equipment to severe chemical and
mechanical environmental factors. A failure in the injection system
will result in a release of additive and could compromise the process
system integrity as well. The designer must consider corrosion of
the injection system by the chemical being added. This corrosion
may be increased by:
•
Higher temperatures at the injection location
•
Flow or turbulence
•
Concentrations from evaporation or extraction as the injected
and receiving streams mix.
The injection system and, in particular, the injection point location
may degrade due to corrosion, erosion, erosion-corrosion, fatigue,
or a combination of mechanisms. Corrosion of the injection point
location, the additive injection line, the co-injectant piping, the
injection pump, and storage tank should be considered. Information
on the corrosiveness of the additive and possible chemical reaction
should be investigated as part of the engineering review process.
Erosion at the injection point location has been attributed to solid
particulate material contained in the process stream. Solids may be
formed by the change in process conditions or when the injection
stream mixes with the process stream. Elbows in piping are usually
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most affected. Erosion rates generally increase with increasing
turbulence and velocity.
Piping configuration and system components, such as elbows,
reducers, and valves, must be considered when choosing an
injection site since data indicates that erosion-corrosion of piping
surfaces and injected or condensed fluids are related. In highvelocity or impingement areas created by the injection of a second
stream, the protective corrosion product layer can be eroded,
increasing the overall corrosion rate at these locations. Erosioncorrosion is particularly severe in elbows and bends where liquid
droplets and high velocity are present. This is why API 570
recommends inspection of up to two elbows downstream of
injection points.
12.3.1.4 Inspection of Injection Point Locations
Injection systems, in particular injection point locations, should be
inspected with a detailed regular program. The design of the
inspection program should include a regular inspection frequency
based on known or anticipated corrosion history. Several unique
types of corrosion are associated with injection point locations,
including:
•
Impingement opposite the injection point or at downstream
changes in pipe direction
•
Corrosivity of the injected chemical itself
•
Insufficient or excessive additive or co-injectant rates.
The API has addressed the inspection of injection points in API 570,
“Inspection, Repair Alteration, and Rerating of In-Service Piping
Systems.” The API code states the required frequency of inspections
and defines the locations for inspection.
12.3.1.5 Location of Injection Point
The location and type of injection point reflect the application
program chosen. To obtain maximum mixing, contact, evaporation,
and/or reaction takes time, and the injection location must be chosen
to allow the desired events to occur in the time and space allowed.
The injection location hardware may vary from a simple tee
connection to multiple injection locations used in parallel to divide
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and distribute an injectant flow. Different injection designs may
require different injection locations to achieve the desired results.
The injection location should be based on the purpose of adding a
chemical or stream, the physical limitations of the system, and the
operational parameters, such as temperature and flow regime. The
choice of injection location must include placement and orientation
of the injector.
12.3.1.6 Co-Injectants
Slipstream carriers or co-injectants are used to increase the volume
of injected streams as a means of controlling the dose rate of the
additive, the mixing of streams, and/or decreasing reaction of the
additive with the process system. A slipstream can be used to
increase distribution of the additive in multiphase systems.
A slipstream is often required to obtain adequate spray patterns or
particle distribution when spray nozzles or quills are used. The
slipstream may be process fluids, steam, water, or gas.
Many chemical additives are corrosive to the process system in very
high concentrations. A co-injectant may be needed to dilute and
prevent flash evaporation of a solvent in a chemical additive and,
thus, avoid the corrosive concentration of the additive.
12.3.2 Injection System Hardware
Injection systems include the:
•
Additive supply piping from tankage
•
Co-injectant
•
Storage tanks
•
Pumps
•
Tank level sight glass
•
Rate gauge
•
Process piping
•
Injection quill and nozzle
•
Monitoring equipment.
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Refinery Injection Systems
A typical injection system for a process additive is shown in Figure
12.1.
Figure 12.1 Typical Chemical Injection System
The type of hardware selected for a specific injection system reflects
the injection parameters. For example, the injection of emulsion
breaker chemistry illustrates a liquid/liquid system where a small
volume of chemical is injected into a very large volume of flowing
liquid. This system requires a large volume bulk tank and an easily
monitored and adjusted additive pump. It also requires strategic
location of the point of injection, which will optimize mixing
through turbulence and shear.
Desalter wash water is an example of the injection of a large volume
aqueous stream into a larger hydrocarbon stream. Care in designing
the mixing of the wash water and crude oil stream will be very
important. The injection of caustic into the desalted crude is an
example of a small volume of non-miscible liquid added for the
purpose of creating a chemical reaction.
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In addition to miscibility, distribution, and mixing, the designer
must consider the:
•
Performance of the materials used in the injection hardware
•
Process equipment within the new environment established at
the injection point.
The remainder of the chapter illustrates various design choices for
injector systems.
12.3.2.1 Chemical Storage Tanks
The selection of a chemical storage tank design depends on the
properties and projected use rate of the chemical. The material of
construction depends on the compatibility between the process
additive and the tank wall. The most common tanks used for oilsoluble products are constructed of carbon steel. Smaller fiberglass
tanks are often used for water-based additives.
All tanks should be vented to accommodate expansion due to
ambient temperature change. Some applications will require flash
arrestors or scrubbers depending on the vapor pressure and
reactivity of the additive. The vent should be designed to prevent
atmospheric contamination as many process additives may react
with condensed water from the ambient humidity. The tank may
require a secondary containment of 100% to 150% of the tank
volume depending on the local permitting regulations.
Bulk tanks, those tanks which are permanently installed and
permitted, are a common type of tanks in use. Bulk tanks may range
from 500 gal. to over 2000 gal. in volume. Semi-bulk tanks are
available in a wide variety of sizes from 90 gal. to 500 gal. The
most common semi-bulk tank is a 350-gal. stainless steel tank. A
system of stacked semi-bulk tanks is a useful alternative to a bulk
tank if space limitations prohibit the use of a bulk tank. A lower,
permanently installed semi-bulk tank is connected to the level sight
glass and pump. Then a replaceable upper semi-bulk tank is stacked
above the first tank.
Deliveries of tanks with a capacity of 1000 gallons or more are often
by tank truck. In these instances, the bulk tank is often placed
adjacent to a roadway. When choosing the location for a tank,
consideration should be given to ease of access for delivery and
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monitoring of the injection system. The chemical injection pump
and rate monitoring equipment would be mounted close to the tank.
The design of the containment would depend on the local
regulations. Generally a dike or similar spill containment will be
required. Permits to install a chemical additive storage tank may be
required.
12.3.2.2 Chemical Injection Pumps
Chemical injection pumps come in a variety of types, sizes, and
materials of construction. Pump selection is an important part of the
injection system design and typically has the greatest impact on the
reliability of the entire system. When selecting a pump, the designer
needs to consider the:
•
Capacity of the pump
•
System pressure
•
Additive viscosity
•
Material compatibility.
Injection pumps are typically positive displacement pumps, which
are driven by electric or pneumatic motors. Pneumatic metering
pumps are widely used for low-volume chemical applications. Gear
pumps are used where large volumes of continuous feed are
required. The most commonly used injection pump is a positive
displacement, electrical drive diaphragm pump.
Pneumatic pumps are available in a variety of sizes and discharge
pressures from several manufacturers. These pumps are very
economical to purchase and are widely used where electrical supply
is unavailable or undesirable. The pneumatic pumps require a
supply of dry air at acceptable line pressure.
When selecting a chemical application pump, the delivery rate
needs to be specified, generally in liters per hour or gallons per hour.
For example, an electrically driven diaphragm pump with a 0.5-in.
actuator and a rate of 24 strokes per minute will deliver 0.6 g/h at
200 psi discharge pressure. The pump is frequently sized to deliver
the desired flow at 50% of pump capacity to allow for process
changes and variation. The design should not be less than 15% of
pump-rated capacity to avoid erratic operation at low volume. The
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delivery pressure calculation should be based on the sum of the
system pressure and the head pressure.
As with the storage tank, the chemical product data sheet should
provide information on material compatibility. Chemical injection
pumps are available in a variety of materials. Both the diaphragm
and piston-type pump are readily available with stainless steel or
Teflon-coated wetted surfaces.
As part of the pumping system, hardware to monitor and control the
chemical additive application process also needs to be considered.
This hardware includes rate gauges or a metering system.
12.3.2.3 Additive Control Systems
Chemical metering systems generally consist of calibrated sight
glasses. These are useful because the low flow rates often preclude
flow meters or other type of meters. One design features a rate sight
glass connected between the chemical tank and the pump. Valves
are attached to allow filling the rate glass. The gauge glass is filled,
isolated from the tank, and the use rate is determined by timing a
loss of volume from the glass.
12.3.2.4 Piping Systems
The piping system includes all pipes, lines, tubing, valves, and flow
meters, which are part of the injection system. Generally, a qualified
refinery design engineer specifies pipe schedule and metallurgy to
meet applicable codes and safety standards.
Check valves are critical for the chemical injection system. It is
suggested that check valves be installed just after the rate gauge, in
the slipstream co-injectant line just prior to the chemical injection
location, and at the inlet to the process stream. Pressure gauges are
suggested at the pump outlet and at inlet to the process unit.
12.3.2.5 Injector
The chemical injector may range from a simple tee connector to
multiple spray nozzles with a slipstream. As with all parts of the
chemical injection system, the choices of the type and design are
based on the objective of the additive program. The integrity of the
injector is critical to the overall performance of the chemical
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additive. Based on this, it is suggested to implement the best
practical design and use the best metallurgy available.
The key design considerations are the location of the injection
nozzle and the system parameters of the process stream into which
the additive is being injected. Retractable injectors, whether quills
or spray nozzles, are preferable in situations where fouling of the
injector can occur during service.
Injection quills are designed to disperse the additive into the flow
stream by the energy from the process stream. There are many quill
designs, but most depend on the velocity of the process stream to
create shear across the quill outlet, dispersing the injective additive
into the process stream. Injection quills are often preferred where
plugging of the device is a concern.
Spray nozzles are designed to have the energy of the chemical
additive create a pressure drop across the nozzle and shear the
additive into a fine mist. Spray nozzles are preferred where
distribution is critical and where the process stream is a vapor. If a
spray nozzle is used, a filter just prior to the nozzle is recommended.
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Chapter 13:Process Additives and
Corrosion Control
Objectives
Upon completing this chapter, you will be able to do the following:
•
Identify the acids commonly encountered in refineries and discuss their roles in corroding equipment and piping
•
Discuss several factors that have a significant effect on the rate
and severity of corrosion
•
Describe several methods available to the refiner that can be
used to reduce corrosion rates
•
Identify several types of chemicals that can be used to combat
corrosion in refineries
•
Discuss specific uses for each type of chemical inhibitor
•
Discuss the importance of optimum corrosion inhibitor dosage
and injection location to successful inhibitor performance
•
Describe a simple injection system.
13.1 Introduction
The costs and results of corrosion are enormous. Corrosion failures
can result in the death and injury of plant personnel and bystanders.
Easily quantifiable costs are those associated with the repair and
replacement of equipment. More difficult to quantify are other
effects of corrosion, such as lower throughput, increased energy
demands, lost production, etc. When corrosion forces a unit to shut
down, the costs of the unscheduled turnaround, lost production (of
the affected unit as well as associated upstream and downstream
units), etc. can be large. Corrosion failures can result in fires,
explosions, and the loss of life.
It is very important to remember that corrosion cannot be stopped.
Corrosion rates can be lessened or minimized, but never reduced to
zero. As a result, there is often controversy over the selection of the
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proper corrosion mitigation strategy. If a corrosion control program
works successfully, corrosion problems are minor, and it is easy to
feel that there were no problems to begin with; that the money spent
on mitigation (chemicals, metallurgy, etc.) may have been wasted.
Similarly, it is sometimes felt that too much chemical was used
when there were no problems. It is only when the amount of
chemical is reduced below some minimum dosage or a chemical is
not used at all that the real effect of corrosion is felt. Then it may be
too late to do much about the problems that have arisen.
One of the reasons that metals corrode is illustrated in Figure 13.1
Figure 13.1 Formation of Metal from Ore and Corrosion of Metal
To produce the elements used in metals and alloys, the pure metal is
recovered from an ore, usually an oxide or sulfide. It requires energy
to do this since the pure element is in a higher energy state than the
ore. Thermodynamics tells us that materials in higher energy states
will return to lower states if at all possible. Corrosion reactions
allow the metal to attain a lower energy state. These reactions occur
spontaneously. Fortunately, corrosion reactions are not usually rapid
reactions.
The types of corrosion that we will deal with in this chapter occur
primarily in the presence of liquid water. There are some types of
corrosion, such as high-temperature sulfidation and corrosion
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caused by naphthenic acids (to be discussed later), that do not
require the presence of liquid water. These are the exceptions rather
than the rule. Of special interest to us is corrosion by acids, both
strong and weak.
The acids commonly encountered are the:
•
Hydrogen halides (hydrochloric acid especially)
•
Hydrogen sulfide
•
Carbonic acid
•
Organic acids
•
Naphthenic acids
•
Acids derived from sulfur oxides (sulfuric and sulfurous acids).
The presence of hydrogen halide acids is due primarily to
incomplete desalting. As the following equations show, calcium
chloride and magnesium chloride will hydrolyze in the presence of
heat and water to give hydrogen chloride (hydrochloric acid in the
presence of water) and the respective metal hydroxides or oxides
(Note: “M” represents calcium or magnesium):
MCl2 + 2 H2O  2 HCl + M(OH)2(1)
or
MCl2 + H2O  2 HCl + MO(2)
The hydrolysis of these salts becomes important as the temperature
increases, especially at temperatures greater than about 250F to
300°F (121C to 149C). Hydrochloric acid is a strong acid,
meaning that it is completely ionized into hydrogen ions
(hydronium ions, H3O+) and chloride ions (Cl-) in the presence of
water. As a result of this complete hydrolysis, a very small amount
of hydrochloric acid can lower the pH of water several pH units and
cause severe corrosion.
Hydrogen sulfide, carbon dioxide, and several lower molecular
weight organic acids all occur naturally in various crudes. Both
carbon dioxide and organic acids can also be produced by oxygen
dissolved in the crude reacting with the hydrocarbons. The solutions
of these acids in water are not as acidic as solutions of strong acids
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in water. These weak acids do not completely disassociate in
water—only a small fraction of the acid ionizes to hydrogen ions
and negative counter-ions.
Naphthenic acid is the name given to a large range of organic acids
that boil in approximately the 350F to 650°F (177C to 343C)
range. As mentioned earlier, naphthenic acid corrosion is one of the
very few types of corrosion that occurs in the absence of liquid
water. These acids consist of one or two five-membered or sixmembered saturated rings, with one or more pendant alkyl groups.
One of these alkyl groups is terminated with a carboxyl (acid)
group.
As mentioned in Chapter 1, Corrosion and Other Failures, crudes
are typically characterized by their neutralization number, a
measure of the amount of acidic species present in the crude or side
cut. The neutralization number is the number of milligrams of
sodium hydroxide (NaOH) needed to neutralize one gram of the
material. As this method measures all acidic species present, the
neutralization number is not a good indicator of the potential
corrosiveness of a crude or side cut.
Methods are available that isolate the naphthenic acids from the
hydrocarbon and then determine the amount of acid present. This
quantifies the amount of naphthenic acids present in the material.
Unfortunately, it is generally believed that all naphthenic acids are
not equally corrosive; some may be extremely corrosive, others only
slightly corrosive.
Sulfur-containing species, such as hydrogen sulfide, thiols,
mercaptans, disulfides, and polysulfides, can react with oxygen to
form sulfur oxide acids. These acids, especially sulfuric and
sulfurous acids, are strong to moderately strong acids that can cause
corrosion as severe as that caused by hydrochloric acid in refinery
process equipment.
In the corrosion reactions with which we are concerned, hydrogen
ions from any of the acids mentioned above are the corrosive agents.
It is only the hydrogen ion that is responsible for the corrosion. The
counter ions, such as chloride, sulfide, and acetate, have a relatively
small effect on the corrosion reaction itself.
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The major differences in the corrosion reactions are the metal salts
that are formed. Most metal chlorides are water-soluble, and some
of the lower molecular weight organic acid salts are also watersoluble. The corrosion product of naphthenic acids, iron
naphthenates, are soluble in hydrocarbons. Corrosion in the
presence of these acids can be severe because the corrosion
byproduct metal salt will dissolve in the water and leave a clean,
active metal surface that will be continuously corroded by the acids
with which it is in contact.
The sulfides of most metals are insoluble in water; the carbonate and
bicarbonate salts usually have very limited solubility. The insoluble
salts can form scales that can help protect the metal from corrosion
by forming a layer between the metal surface and the corrosive
environment. The ability of this layer to protect the base metal
depends greatly on pH, temperature, and other ions present. These
factors can change the tenacity and/or porosity of the film, changing
its protective nature.
13.2 Factors Affecting Corrosion
Several factors have significant effects on the rate and severity of
corrosion. Changes in processes or conditions can help lessen the
effects of some of these factors. However, unfortunately, the refiner
cannot change many of the factors, or cannot change them enough
to significantly influence corrosion rates.
13.2.1 Acids
The amount and types of acids in the water are major factors in
controlling the severity of corrosion. The less acid present, the fewer
hydrogen ions present, and the less severe the corrosion. The refiner
can control the pH of the condensed water. Methods of controlling
pH will be examined later in the chapter.
13.2.2 Temperature
Temperature can have a dramatic effect on corrosion for several
reasons. Lower temperatures cause chemical reactions, including
corrosion reactions, to slow down. Higher temperatures increase
corrosion rates unless the higher temperature prevents the formation
of liquid water.
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If the temperature of a process can be changed some, this gives the
refiner the possibility of controlling the location of water
condensation and/or salt deposition, moving the location of the
corrosive environment. By doing this, the refiner has the advantage
of locating the corrosion in an area that is more resistant to or less
affected by corrosion or more easily treated with chemicals.
13.2.3 Pressure
The main effect of pressure is to influence the concentration of
gases, such as hydrogen sulfide and carbon dioxide, in the water and
hydrocarbon present. Increasing pressure increases the solubility of
gases in water, thereby decreasing the pH of the water. As a result,
corrosivity of the water is markedly increased.
13.2.4 Flow
Related to the temperature and pressure of an operation is the flow
regime of the liquid(s) and gas phases. There may be more than one
liquid phase present, especially when water is present. Several
conditions affect the liquid phase, including:
•
Pipe diameter
•
Amount of liquid(s) present
•
Amount of gas present
•
The density of the gas and liquid phases
•
Orientation of piping.
The liquid(s) may exist anywhere in the range of a finely dispersed
mist to a separate, stratified phase(s). The dispersed and annular
mist regimes are considered to be the best flow regime because the
mist acts almost as if it were a gas, allowing fairly rapid thermal and
chemical equilibria between the liquid and gas phases.
Any chemical that is dispersed into a stream such as this should
make good contact with almost all of the liquid and gas present.
Any stratified flow regime, such as slug and wave, can lead to
corrosion and/or erosion. Stratified flow prevents intimate mixing of
the phases, slowing down all equilibrium and mass transport
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phenomena and affecting the ability of filming amines to reach
metal surfaces.
13.2.5 Turbulence
Turbulence generally increases corrosion rates. This happens
because turbulence can remove protective corrosion product scales
on the surface of the metal, opening a path for more corrosion to
occur.
13.2.6 Material Selection
The proper choice of metallurgy can greatly influence the corrosion
of equipment. Some alloys are very resistant to attack by strong
acids, others to strong bases, others to weak acids, oxygen, and so
on. Using the correct alloy in a corrosive area can, in the long run,
save money even though higher alloys are more expensive than mild
steel.
When there is more than one metal or alloy present in a system,
galvanic corrosion is always a possibility. As mentioned in Chapter
1, galvanic corrosion is caused by the difference in reactivity of two
dissimilar metals that are in electrical contact with each other and in
a conductive, corrosive medium. Shell and tube exchangers are
subject to galvanic corrosion when the shell is constructed of
different metal than the tubes. During turnarounds and revamps,
existing equipment or piping is sometimes replaced with materials
made of different metallurgy and, as a result, galvanic cells are
established. Galvanic corrosion is the reason that sacrificial anodes
are used to protect underground and underwater equipment—the
more active/reactive anode (which is easily replaced) is consumed
and in the process protects the less active/reactive cathode.
Even though corrosion is a process we want to minimize, it can be
beneficial. When most metals are corroded by hydrogen sulfide, an
insoluble, passive metal sulfide is formed. Frequently, this film will
adhere to the base metal, providing a degree of protection to the
base metal. The sulfide film acts as a physical barrier, separating
the metal from the corrosive environment, slowing the diffusion of
corrosive species from the environment to the metal surface.
Finally, the presence of other factors, such as corrosion inhibitors,
can play a major role in controlling the rate of corrosion. The
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chemistry, use, and application of various classes of corrosion
inhibitors follow.
13.3 Methods to Mitigate Corrosion
There are several methods available to the refiner that can be used to
reduce corrosion rates. These include:
•
Upgrading metallurgy
•
Reducing the amount of corrosives produced
•
Reducing the concentration of corrosives
•
Changing the nature of the passive film
•
Changing the location of the corrosive environment
•
Using corrosion inhibitors.
13.3.1 Desalting and Caustic Injection
If the production of corrodents can be reduced, there will be less
potential for corrosion. For example, good desalting and careful
caustic injection are commonly used in atmospheric distillation
units. Desalting lowers the amount of calcium chloride and
magnesium chloride that might be converted to hydrochloric acid.
Caustic injection converts the calcium chloride and magnesium
chloride to hydroxides and sodium chloride. Sodium chloride does
not hydrolyze to hydrogen chloride to any appreciable extent at the
temperatures that we are concerned with.
13.3.2 Water Washing
By lowering the concentration of the corrodent acids, we will
generally increase the pH and lower corrosion rates. To accomplish
this, a water wash is used in the system upstream of the condensers.
The addition of water (or steam) into a fixed amount of corrosive
materials will dilute the corrosives when these materials condense to
liquid water. Also, a good water wash will dissolve any watersoluble materials present, thereby preventing underdeposit
corrosion.
Although a good water wash will help prevent corrosion, there are
several factors to be considered before implementing such a
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program. When water is injected into a hot overhead vapor line, the
evaporation of the water will remove heat from the vapors. If the
unit is well heat-integrated, the heat removed must be made up
somewhere else, usually by burning fuel. In addition, accumulators
or separators may not be able to handle the increased water load,
especially if they are operating close to their design capacities.
The source of the wash is very important—only good quality water
should be used. Waters that contain appreciable amounts of
dissolved or suspended solids should be avoided because these
materials will deposit in the overhead lines as the water evaporates.
These deposits could become a source for underdeposit corrosion.
Water that contains oxygen should also be avoided as oxygen can
cause very severe underdeposit pitting corrosion. Boiler feed water
is the best choice of wash water, but is rarely available in sufficient
quantities. The most commonly used wash water sources are:
•
Atmospheric and vacuum tower accumulator waters
•
Sour water stripper water.
13.3.3 Acid Neutralization
Another method used to minimize corrosion caused by acidic
species is to neutralize the acids. The acids will react with bases,
such as ammonia and amines, to form salts. The aqueous solutions
of these salts are much closer to pH 7 than the original solution of
acids in water and, as a result, corrosion is reduced.
13.3.4 Barrier between Metal and Environment
If a barrier between the environment and the metal can be
established, corrosion can be prevented. This barrier can be a visible
one, such as a coating of paint or plastic, or it can be a passive layer
of corrosion products. Also, it can be a barrier on the molecular
level that is composed of one or a few layers of protective
molecules. Filming amine chemicals are an example of a material
that forms a protective barrier.
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13.4 Chemicals Used to Combat
Corrosion
Several types of chemicals are used to combat corrosion in
refineries. The most commonly used are filming amines and
neutralizing amines. Filming amines are used primarily to protect
metal from weak acids, especially hydrogen sulfide. Neutralizing
amines help prevent corrosion caused by strong acids, such as
hydrochloric acid and the sulfur oxide acids.
Other chemicals used to fight corrosion include:
•
Caustic to prevent the formation of and/or react with hydrochloric acid
•
Polysulfides to react with cyanide to help prevent hydrogen blistering and/or change the nature of the protective layer of corrosion products
•
Oxygen scavengers
•
Naphthenic acid corrosion inhibitors.
13.4.1 Filming Amines
Filming amine and filmer are generic terms used to indicate a large
class of materials that form somewhat adherent films on metal and
scale surfaces. The materials are most commonly either amines or
reaction products of amines in which the amine has one or more
relatively large alkyl groups attached to a nitrogen. Some filmers do
not contain any basic nitrogens, but consist of other polar and/or
surface-active chemicals. The most common chemical classes of
materials and their structures are shown in Figure 13.2.
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Figure 13.2 Filming Amine Structures
The classical explanation of how filming amines work still has
utility even though it is somewhat simplistic. Basically, the filming
amine provides a barrier between the metal and the corrosive
aqueous environment. This is shown in Figure 13.3 by the long alkyl
tails of the inhibitor and the hydrocarbon attracted to these tails that
prevents the metal from being wetted by water.
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Figure 13.3 Classical Filming Amine Mechanism
The polar heads of the inhibitor molecules are attracted to the metal
(and scale) surface by weak van der Waals forces. The film is in
equilibrium with the environment—molecules of inhibitor are
continuously adsorbing and desorbing from the surface.
To provide effective protection, the inhibitor concentration in the
bulk phase must be sufficient so that there will be enough molecules
present in solution to rapidly replace any inhibitor molecule that
desorbs from the metal/scale surface. To achieve this, filming
amines are applied at a constant, low rate.
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Filming amines are almost always used in conjunction with
neutralizing amines in crude units. This is done because filming
amines tend to lose effectiveness as the pH decreases. At a lower
pH, generally less than about a pH of 4, the amine portion of the
filming amine becomes more protonated, increasing its solubility in
water and decreasing its attraction for the metal/scale surface.
Protonation increases the rate of desorption, making the required
equilibrium concentration of the filmer in the bulk phase difficult to
maintain economically in most applications. By keeping the pH
above about 4, the overall efficiency of the filmer is maintained.
13.4.2 Filmer Formulation
A typical formulation of a filming amine product consists of:
•
The corrosion inhibitor
•
One or more solvents
•
Small amounts of emulsion breakers and/or wetting agents that
are sometimes used.
The amount of active material will vary as will the amounts and
types of other materials in the formulation. These products are
generally supplied as hydrocarbon solutions, but some filming
amine corrosion inhibitors are available in water-based
formulations. In general, the solvent system should be similar to the
bulk liquid phase of the system being treated.
13.4.3 Filmer Application
In distillation equipment, filmers are generally applied to the
overhead vapor transfer line. The filming amines are usually
injected into the line using a quill or atomizing nozzle after being
mixed with a hydrocarbon slipstream. The slipstream is used to
dilute the inhibitor and help ensure a more even distribution of the
inhibitor in the vapor phase.
Filming amines have been used to help reduce corrosion in the
upper trays of towers if the temperature is near the water dewpoint.
The filmer is added to the naphtha reflux stream and will work its
way down from the reflux return tray, protecting all areas that it
contacts. Filming amines are used in many other applications
including, but not limited to:
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•
Amine units
•
Sour water strippers
•
Coker overheads
•
FCCU overheads.
Process Additives and Corrosion Control
13.4.4 Treat Rates
Treat rates vary depending on the:
•
Type of inhibitor
•
Concentration of active ingredient(s) of the inhibitor
•
Severity of the corrosion problem
•
System temperature and pressure.
Treat rates are based on either total crude charge or the overhead
hydrocarbon rate. It is often recommended that when treatment first
begins the filming inhibitor be added at two to four times the
expected treat rate to help build up a protective film rapidly.
13.4.5 Monitoring Filmer Performance
The effectiveness of filming amines and optimization of their use
rates are determined by monitoring corrosion in the system being
protected. Common methods are electrical resistance probes,
corrosion coupons, and water analyses. These methods are
addressed in Chapter 14, Corrosion Monitoring Methods in
Refineries.
Since filming amines are naturally surface-active and many
formulations contain other surface-active agents, these products can
cause problems in the accumulator and in the product naphtha.
There can be a tendency to form an emulsion in the accumulator if
the filmer is not formulated properly. The inhibitor, generally being
hydrocarbon-soluble, will be carried along in the naphtha and can
affect the Water Solubility Index, Modified (WSIM) number of
gasoline made from this naphtha. WSIM is a measure of the amount
of water that is dissolved or dispersed in a hydrocarbon, especially
motor and aviation gasolines. High WSIM values, indicating low
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amounts of water, are desired to help prevent corrosion and gas-line
freezing.
When filming amines are used in light end units, care must be taken
to ensure that the filmer is soluble in the hydrocarbon stream being
protected. Light aliphatic hydrocarbons are very poor solvents.
Filming amines with very limited solubility in the light ends can
deposit on any surface that they come in contact with, forming
fouling deposits.
13.4.6 Neutralizing Amines
Neutralizing amines are basic, nitrogen-containing organic
compounds. They are used to neutralize the strong acids (primarily
hydrogen chloride) formed in the distillation process.
Several chemicals are used as neutralizers. The least expensive is
ammonia. The structures of several of the commonly used organic
neutralizers are shown in Figure 13.4.
Figure 13.4 Neutralizing Amines
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Other amines, such as cyclohexyl amine, the methyl and ethyl
amines, the ethanolamines, and longer-chain alkyl amines, are also
used. Mixtures of amines are also available.
In the discussion that follows, ammonia and the neutralizing amines
will both be included in the terms neutralizing amine or neutralizer.
It should be noted that ammonia is not an amine since it contains no
carbon atoms.
The chemistry involved in neutralization is simple—the reaction of
a base with an acid. The equations follow:
 Salt
NaOH + HCl  NaCl (+ H2O)(3)
H-NH2 + HCl  H-NH3+ Cl-(4)
Base + Acid
ammonia
ammonium chloride
(ammonia hydrochloride)
R-NH2 + HCl
amine
 H-NH3+ Cl-(5)
amine hydrochloride

H2N-R-NH2 + 2 HCl
H3N+-R-NH3+ 2 Cl-(6)
diamine
diamine dihydrochloride
The stoichiometry of the neutralization reaction is that one basic
nitrogen can react with (neutralize) each acid proton. This one-toone mole stoichiometry cannot be improved by changing amines,
changing the injection point, etc. However, by injecting the
neutralizer in the wrong place or with the wrong equipment, it is
possible to lower the efficiency so that not all of the injected
neutralizing amine will react with the acid present.
If the neutralizer is not atomized well, large drops or even a stream
of the neutralizer could impinge on the wall of the vapor transfer
line and collect in low places in the line. This impingement could
cause erosion-corrosion of the wall. The neutralizer in the pools or
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puddles would not be available to neutralize acids, thus wasting the
chemical.
If the neutralizer is injected too close to exchangers, especially those
with unsymmetrical arrangements, the amine quite possibly would
not be evenly distributed in the overhead vapor. This would result
in some exchangers getting excess base and others insufficient base
to neutralize the condensing acidic water. Also, injecting the
neutralizer too close to the water condensation point greatly limits
the time that the amine has to react with the acid before the acid
condenses in the water.
As mentioned previously, the reaction of a neutralizer with an acid
forms a salt. The dry hydrochloride salts of many amines are solids
at the temperature of overhead systems. Several amine
hydrochloride salts have melting points between 150°F and 220°F
(66C to 104C). Since these hydrochloride salts will not be solid in
dry systems if the temperature is greater than their melting point,
they will not directly cause solids fouling. However, the liquid salts
can be absorbed onto and into existing scales and deposits, reducing
the mobility of the salts, and lead to underdeposit corrosion and
fouling by corrosion products.
Neutralizing amine hydrochloride salts are soluble in water and
generally insoluble in hydrocarbons. The ethylene diamine (EDA)
salt has the highest thermal decomposition temperature of the
commonly used neutralizers. Its salt also is the least soluble in water
(about 30% by weight in hot water) and so care must be used if EDA
is applied in a relatively dry system to prevent solids from building
up. An effective water wash program can prevent this solids buildup
problem and also help prevent corrosion from occurring under these
deposits.
Amine salts can also get in the tower and add to existing deposits
and scales. If the neutralizing amine is added directly to the tower,
usually by adding it to the reflux return, the amine will react with
hydrogen chloride to form the salt in situ. If the amount of hydrogen
chloride is low and/or the temperature is high, the potential for salt
deposition is small. If greater amounts of acid are present and/or the
temperature is relatively low, the salt could be stable and may form
a deposit. In a similar manner, the addition of a neutralizing amine
to the feed, whether before or after the desalters, can introduce
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amines and amine salts into the tower where, if the wrong amine is
chosen, there is the potential for the salts to lay down and add to
tower and tray plugging and corrosion problems.
The water in the accumulator contains small amounts of neutralizer
salts, generally less than 100 ppm to 200 ppm. If there is poor water
separation in the accumulator some of this water can be entrained in
the naphtha that is sent back to the tower and slowly add salt to the
tower. (This argument is only for physically entrained water; the
water that is soluble in the naphtha is believed not to contain any
salt.)
Another possible means for getting small amounts of ammonium
chloride and neutralizer salts into the tower is through the use of the
atmospheric or vacuum tower accumulator water in the desalter. A
small amount of the desalter water, typically less than 0.5%, enters
the tower with the hydrocarbon feed. The amine salt dissolved in
this water will be heated with the crude. At these temperatures, the
salt will either decompose or sublime. The nitrogen-containing
portion of the salt can thermally decompose into smaller, lower
molecular weight amine or ammonia or amine or ammonia salts.
These salts and/or the original salt can sublime to a cooler section of
the tower and deposit there. This is commonly an issue when
ammonia is used as the primary neutralizer. The decision of whether
to use ammonia or a neutralizing amine must be made carefully. If
neutralizing amines are chosen to combat corrosion, the specific
neutralizing amine must also be carefully determined.
Ammonia was the first neutralizer used. It was readily available and
provided passably acceptable protection of the overhead
condensers. The handling of ammonia, especially gaseous
ammonia, still causes corrosion control problems. Because of
pressure changes on the unit, it is sometimes hard to control the feed
rate of ammonia gas unless dual regulator systems are used.
Another major drawback of using ammonia is that it does a very
poor job of protecting the area where water first begins to condense.
Ammonia behaves like a typical gas and is not very soluble in hot
water. Therefore, it does not enter the water when it first condenses.
Unfortunately, hydrogen chloride is very strongly attracted to the
hot water that first condenses and will greatly depress the pH in this
region. Since ammonia does a poor job of protecting the area where
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water first begins to condense, corrosion is not controlled in this
area. Ammonia can be used reasonably successfully only in a
system that is not too aggressive (low amounts of acid present), has
large amounts of water present, and is well monitored. If there are
relatively high amounts of chloride present, or if no corrosion
monitoring program is in place, ammonia should not be used.
Great care must be exercised whenever ammonia is used in systems
with copper-containing alloys. Free ammonia, found in basic
solutions, is capable of complexing with elemental copper and
removing it from alloys. Neutralizing amines share this property
with ammonia and must also be used with care in these systems.
The choice of the target pH in the accumulator is important. If the
target pH is too low (less than 4.5), it is possible to have severe
corrosion if there is a sudden increase in the amount of acids going
overhead or a decrease in neutralizer addition rate. At a pH greater
than about 7.0, several things can happen. Corrosion caused by the
bisulfide
ion will increase as more and more hydrogen sulfide dissolves and
reacts with base to form the bisulfide species. Bisulfide ions form
less protective iron sulfide films and can react with existing iron
sulfide films to partially convert them to bisulfide films, forming a
less protective film. Because of the buffering effect caused by the
various weak acids that can be present, it is sometimes very difficult
to raise the pH above 6 to 7. The increase in cost of neutralization as
pH is increased can make running at a pH of greater than 7 difficult
to justify. Neutralizer use rates can increase from two up to ten fold
for each unit increase in pH.
It is important to remember that the most common pH measurement
that can be obtained from a unit is of the accumulator water. This
value does not necessarily reflect the pH throughout the condensing
system. This pH difference has been shown by the use of laboratory
simulators as well as various on-line sidestream devices. As
mentioned above, ammonia does not enter the hot acidic water and
so the pH in the region of first condensation of water is lower than
the pH in the accumulator. Most neutralizing amines are more
strongly attracted to the first condensing water than is ammonia and
so provide much improved pH control in this area.
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In general, neutralizing amines are preferred over ammonia for
several reasons, including:
•
The organic amines are usually easier to handle
•
They provide much better protection in the region where water
first condenses
•
They have lower decomposition/melting points
•
They have more water-soluble hydrochloride salts
•
They are generally less aggressive toward copper-containing
alloys.
These amines also tend to offer better pH control with fewer pH
excursions and frequently have lower tendencies to form deposits
than does ammonia.
13.4.7 Polysulfides
Polysulfides are materials that contain several sulfur atoms
connected to each other, as shown in the formula:
M-S (-S)x-S-M
where M is usually ammonium or sodium.
Polysulfides are used to help combat hydrogen blistering, cracking,
and embrittlement problems encountered in fluid catalytic cracking
unit (FCCU) equipment. Ammonium polysulfide can be prepared
from sulfur and stripped sour water or purchased from some
chemical suppliers.
Hydrogen blistering generally requires the presence of a weak acid,
most commonly hydrogen sulfide. Atomic hydrogen is the first
product in the reduction of protons to hydrogen gas. Usually, two
atomic hydrogens combine rapidly to form molecular hydrogen. If,
for some reason, the atoms do not combine, they can migrate into
the metal and recombine inside. The atoms will recombine at grain
boundaries, inclusions, and imperfections in the metal. They can
recombine to form hydrogen molecules or react with carbides
present at grain boundaries to form methane gas, increasing pressure
at these sites. Eventually blisters will form in the metal, decreasing
its strength. See Figure 13.5.
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Figure 13.5 Hydrogen Blistering
Hydrogen blistering is most commonly found in catalytic cracking
equipment where waters laden with cyanide, bisulfide, sulfide, and
ammonia are present. Cyanide plays an important role in hydrogen
blistering as shown by Equation 7, below:
FeS + 6 CN-
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 Fe(CN)6-4 + S=(7)
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When cyanide reacts with iron sulfide, it forms the ferrocyanide
complex and helps destroy the semiprotective iron sulfide film,
exposing fresh metal to attack by the acids present.
Polysulfides provide protection by two generally accepted
mechanisms. First, they react with cyanide to form thiocyanate as
shown in the equation below:
CN- + Sx=
 SCN- + S(x-1)=(8)
Chemically, one sulfur atom from the polysulfide is required to react
with one cyanide ion. To be certain that there is no unreacted
cyanide present, there must be an excess of polysulfide at all times.
The excess polysulfide is usually detected by the yellow color it
imparts to the accumulator water. If the system contains a large
amount of cyanide, the cost of polysulfide can be prohibitive.
Secondly, polysulfides are believed to change or stabilize the nature
of the passive sulfide film on the metal surface. Polysulfide can
transform the iron sulfide scale to an iron polysulfide scale, which
might be more resistant to further corrosion than the original scale.
Filming amines have also been shown to be effective in the
prevention of hydrogen blistering. As in distilling units, they are
added continuously in small amounts upstream of the point of water
condensation to help reduce the corrosion rate. By reducing
corrosion, they reduce the amount of hydrogen atoms formed.
There is also evidence that filmers can directly reduce the rate of
atomic hydrogen migration into the metal.
13.4.8 Naphthenic Acid Corrosion Inhibitors
Several chemicals have been patented to help mitigate the effects of
naphthenic acid corrosion. Their effectiveness depends greatly on
the site of application, the amount of chemical used, the
temperature, the amount (and type) of naphthenic acid, and the
turbulence of the system. They typically form a more corrosion and
erosion-resistant barrier between the base metal and the corrosive
environment than hydrogen sulfide does.
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13.4.9 Application of Corrosion Inhibitors
A corrosion inhibitor can help reduce corrosion only if it gets to the
site of the corrosion. This requires that the chemical is applied in
the correct amount and at the correct location. Typically, this
involves using an injection device (quill or nozzle, preferably
retractable) and sometimes using a diluent stream (water or
hydrocarbon).
The purpose of a chemical injection system is to introduce the
corrosion inhibitor into the stream to be treated such that the
inhibitor is uniformly dispersed in the stream, as a liquid or vapor as
appropriate. The inhibitor should be present wherever corrosives are
present in an amount that provides adequate corrosion protection.
Injection systems are usually designed to disperse the chemical into
extremely fine droplets.
A secondary function of a chemical injection system is to keep the
neat corrosion inhibitor away from the equipment walls. This is
important because many chemicals, even corrosive inhibitors, can
be corrosive, especially at elevated temperatures. It was common in
the past, and unfortunately is not rare today, to have chemicals
injected into any valve, tee, etc. that is convenient. Not only does
this not provide good distribution of the chemical, it also can cause
severe corrosion. For example, neutralizing amines can form salts
on the pipe wall. The high pH of the unreacted amine can increase
bisulfide corrosion. The addition of filming amines, especially if
they are not diluted with a carrier solvent, through a tee is known to
be responsible for corrosion failures. A cautionary sidenote—some
antifoulants are corrosive at elevated temperatures, and they too are
often added to hot hydrocarbon streams.
When a corrosion inhibitor is injected into a liquid-filled line, the
inhibitor will dissolve in the liquid if the two liquids are miscible, or
it will stay as a separate phase if they are immiscible. If they are
miscible, the dissolution of the inhibitor into the liquid helps assure
uniform distribution. If the two materials are immiscible, a very fine
dispersion of the inhibitor is required to help assure uniform
distribution in the liquid. Fine dispersions also tend to coalesce
relatively slowly, thus keeping the chemical from forming a second
bulk phase in which the inhibitor is concentrated and not readily
available to provide any protection to the system.
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When a nonvolatile corrosion inhibitor, such as a filming amine, is
injected into a vapor stream, fine dispersion of the inhibitor is even
more important than when it is injected into a liquid-filled line. A
droplet of liquid moving in a vapor stream has much greater
momentum and inertia than an equal volume of vapor. As a result,
droplets, especially large droplets, tend not to negotiate changes of
direction well and impinge on the outer radii of bends and ells.
Thus, dispersion of the corrosion inhibitor into the finest droplets
possible is essential to help ensure good distribution of the inhibitor.
If evaporation of the inhibitor into the vapor is desired, as is usually
the case when a neutralizing amine is being added into an overhead
line, good dispersion is also necessary. The evaporation rate of a
material is proportional, among other things, to its surface area.
Smaller droplets have surface area/mass ratios that are greater than
larger droplets and so evaporate more rapidly. Once the inhibitor is
in the vapor phase, it will mix in the overhead vapor readily (given a
little time) and will not impinge on walls, etc.
Dilution of nonvolatile corrosion inhibitors, typically filming
amines, in a carrier solvent, such as water or overhead naphtha,
helps distribute the chemical in the stream to be treated, especially if
the stream is a vapor. When the diluted inhibitor is dispersed by the
injection system, each droplet contains a relatively small amount of
inhibitor dissolved in the solvent. If the solvent evaporates, the
amount of remaining inhibitor is minute, and it now exists as an
extremely small particle that is less prone to impinge on the walls of
bends and ells.
The simplest injection system consists of an open-ended pipe
inserted into the system to be treated. It is better to have the pipe end
cut at an angle or have the pipe capped and the pipe perforated with
a series of small holes. Atomizing nozzles provide very fine droplets
but, because their orifices are generally small, they are subject to
plugging by tramp material found in the delivery system (tanks and
piping) unless fine filters are used.
The metallurgy of the injector is important when it is in a corrosive
system or contains a corrosive chemical. An injector in an overhead
line acts as a cold finger (a small condenser or heat exchanger) and
can cause condensation of very corrosive fluids on the outside of the
injector.
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The type of injection system, its metallurgy, the diluent, and diluent/
inhibitor ratio are often defined by one of the safety or materials
departments of the refinery. When this is not done, or when more
than one option is allowed, the choice typically becomes the
responsibility of the equipment owner. Chemical suppliers can be
good sources of information about injection systems because they
have a very vested interest in getting the best possible distribution of
their chemical.
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Chapter 14:Corrosion Monitoring in
Refineries
Objectives
Upon completing this chapter, the student will be able to do the
following:
•
Define the purposes of corrosion monitoring
•
Identify the major categories of corrosion monitoring techniques
•
Identify the principal benefit of corrosion coupons
•
Recognize the factors used in calculating corrosion rate in corrosion coupons
•
Identify the mechanism employed in the use of electrical resistance monitoring
•
Recognize the factors used to calculate the resistance factor
employed in the use of electrical resistance monitoring
•
Identify the principle weakness of electrical resistance monitoring
•
Describe the premise on which electrochemical corrosion monitoring is based
•
Recognize the factors used to calculate corrosion rate in electrochemical corrosion monitoring
•
Identify the various types of electrochemical corrosion monitoring methods
•
Describe the relationship between the corrosion rate and polarization resistance upon which LPR is based
•
Describe the principal use for potential monitoring
•
Describe the principal use of zero resistance ammetry
•
Describe the principal use of electrical impedance spectroscopy
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•
Identify the difference between current noise and potential noise
in electrochemical noise analysis
•
Identify the difference between intrusive and non-intrusive
hydrogen flux monitoring
•
Identify one or more limitations in the use of hydrogen probes
•
Identify one or more characteristics of corrosion monitoring sites
•
Identify one or more characteristics of corrosion hot spots which
require corrosion monitoring in refineries
•
Identify one or more corrosion monitoring sites in specific refinery process units
•
Identify one or more sources of inaccuracy involved in on-line
process monitoring.
14.1 Introduction
Corrosion monitoring is fundamental to the safe and economical
operation of a petroleum refinery. This chapter presents a basic
overview of the corrosion monitoring methods in use in today’s
refineries, ranging from simple corrosion coupon techniques to
advanced electrochemical methods.
Some of these systems are designed to be combined, insuring the
accuracy and consistency of monitoring information.
Major sources of corrosion in refineries include:
•
Dew point corrosion in overhead systems
•
High-temperature non-aqueous corrosion
•
Aqueous sulfide corrosion
•
Strong acids used as catalysts
•
Amine solutions used in gas sweetening.
Each situation poses a different set of conditions that must be
analyzed and monitored accordingly.
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14.2 Uses of Corrosion Monitoring
Corrosion monitoring in refineries is used for several reasons
including:
•
Diagnosis of corrosion problems
•
Monitoring corrosion control methods
•
Advanced warning of system upsets leading to corrosion damage
•
Invoking process controls
•
Determination of inspection and/or maintenance schedules
•
Estimating service life of equipment.
14.3 Corrosion Monitoring Techniques
Corrosion assessment can be complex since refinery operations
provide a wide variety of environments and service conditions. No
single corrosion monitoring method will work in all applications.
Multiple measurement technologies may be needed in combination
to provide accurate and reliable data. Some methods are useful for
periodic or continuous on-stream measurements. Others are used
during shutdowns or for new construction.
Four basic categories of corrosion monitoring techniques are direct,
indirect, intrusive, and non-intrusive. Table 14.1 illustrates the
relationships of these types of monitoring methods.
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Table 14.1: Types of Corrosion Monitoring Methods
Intrusive
Direct
Corrosion coupons
Electric resistance (ER)
Linear polarization resistance
(LPR)
Non-intrusive
Indirect
On-line pH or water analysis
Internal hydrogen flux probes
Ultrasonic testing
Radiography
External hydrogen flux probes
Analysis of water samples
obtained through an existing
valve
Surface patch hydrogen
probes
Direct techniques, which measure a direct result of corrosion,
include corrosion coupons, the electric resistance (ER) technique,
and linear polarization resistance (LPR). Indirect techniques, which
measure an outcome of the corrosion process, include ultrasonic
testing and radiography. Both techniques can be used to determine
the remaining wall thickness of a pipe, vessel, or other equipment
affected by corrosion.
Intrusive techniques, which require entry into the process stream,
include corrosion coupons, ER and LPR probes, and on-line pH or
water analysis. Non-intrusive techniques include external hydrogen
flux probes and analysis of water samples obtained through an
existing valve.
14.3.1 Corrosion Coupons
Corrosion coupons are tabs of metal that reside in the process stream
and can be removed for analysis of corrosion rates. Corrosion
coupons provide the most reliable physical evidence possible, but
the technique is often overlooked because it is considered by some
to be archaic.
Corrosion coupons yield information on the average-mass-loss
corrosion rate as well as on the extent and distribution of localized
corrosion. Coupons also provide information on the nature of
corrosion through analysis of corrosion products.
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The main disadvantages of coupons are that they usually require
significant time in terms of labor, and they provide time-averaged
data rather than real time or on-line corrosion monitoring. Coupons
should be used to provide periodic information, and their data
should be considered a basis of comparison for all other methods.
ASTM G4, “Standard Guide for Conducting Corrosion Coupon
Tests in Field Applications,”1 provides procedures for in-plant
corrosion coupon testing. ASTM G1, “Standard Practice for
Preparing, Cleaning, and Evaluating Corrosion Test Specimens,”2
provides guidelines for preparing, cleaning, and weighing corrosion
coupons.
The corrosion rate equation employed in the analysis of corrosion
coupons is:
Corrosion Rate (in mmpy) = (8.76 x 104) M/ADT, where:
M = mass loss resulting from the difference in initial and
final specimen weights (in grams)
A = coupon surface area (cm2)
D = material density (g/cm3)
T = time of exposure (hours)
The corrosion rate in mm/y can be converted to mils per year (mpy)
by multiplying by 40.
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Figure 14.1 Typical Plot of Metal Loss versus Time
Figure 14.1 illustrates the differences between the average corrosion
rate as determined by coupons and the instantaneous rate as a result
of a system upset. Since the average rate assumes that the corrosion
rate of the metal is uniform, it is very important to evaluate the
coupons visually for localized corrosion. ASTM G46, “Standard
Guide for Examination and Evaluation of Pitting Corrosion,”3 gives
procedures for analysis of localized corrosion, and Figure 14.2
illustrates the common types of localized corrosion found on
surfaces as defined by this standard. Determining the density
(number of pits per unit area), size (diameter), and depth of the
localized attack can assist in evaluating the mode of corrosion.
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Figure 14.2 Types of Pitting
Useful parameters for localized corrosion are the:
•
Ratio of maximum localized attack rate to the general corrosion
rate determined by mass loss
•
Percent of corrosion-affected area on the coupon.
If the ratio of pitting rate to general corrosion rate is low, the general
corrosion rate serves as an accurate predictor of corrosion
performance. In cases of oxygen ingress, pitting of stainless alloys,
and velocity-accelerated corrosion (naphthenic acid corrosion), the
local attack rate can be over ten times the general corrosion rate.
14.3.2 Electrical Resistance Monitoring
In Electrical Resistance (ER) monitoring, the ER probe is comprised
of a sensing element made from wire, strip, or tube, which is used to
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conduct an electrical signal. A schematic drawing of a typical ER
probe is shown in Figure 14.3.
Figure 14.3 Schematic of ER Probe
When exposed to a corrosive environment, the cross-section of the
wire, strip, or tube is reduced over time, increasing the resistance of
the sensing element, thus producing a change in the output of the ER
meter according to the formula:
R = s(L)/A, where
R = resistance
s = resistivity of the metal
L = length of the sensing element
A= cross-sectional area
Information on using this technique can be found in ASTM G96,
“Standard Guide for On-Line Monitoring of Corrosion in Plant
Equipment (Electrical and Electrochemical Methods).”4
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The main benefit of the ER technique is that it can be used on in-line
process monitoring, with multiple probes used to access various
locations in the process stream. Telemetry can be used to send data
back to a central location so corrosion rates and the effects of
process changes can be identified. One of the most beneficial
aspects of the ER technique is that it does not require a continuous
electrolyte current path to make measurements. This allows the
method to work in multiphase environments in which several
chemicals are alternately present in the process flow. Thus, ER can
be used for monitoring corrosion in environments containing
distinct aqueous and hydrocarbon phases. They can also be used in
non-aqueous environments, such as those in which sulfidic and
naphthenic acid corrosion may be present.
Figure 14.4 shows ER data taken over a 14-day period. During this
period, the corrosion rate begins at 25 mpy, drops to a low of 5 mpy,
and then increases to 12 mpy.
Figure 14.4 ER Probe Data versus Time
The ER technique does have some limitations. Data is provided only
for general corrosion and not localized attack. ER probes require
several days to determine a reliable corrosion rate trend and,
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therefore, if the process is prone to rapid changes in corrosivity, ER
probes may not provide accurate data.
Where hydrogen sulfide (H2S) is present, ER probes can be prone to
error due to the presence of conductive sulfide corrosion products
on the sensing element. The results of ER probes should be
compared to those obtained from coupon exposures. While ER data
may not provide reliable measurements of the absolute corrosion
rate, they can yield helpful indications of trends and changes in
plant corrosion activity.
14.3.3 Electrochemical Corrosion Monitoring
Electrochemical corrosion monitoring is based on the premise that
corrosion is an electrochemical process that can be monitored by
measuring potential and current that characterize the corrosion
process.
In a basic model, corrosion processes can be described as an
electrochemical potential (voltage) and a current (amperage) that
indicate the rate of the process. The corrosion current (icorr) is
converted into a corrosion rate by applying Faraday’s Law,
according to the equation:
Corrosion Rate = K (icorr)(EW)/D
K is a constant
EW = the equivalent weight
D = the density of the metal
Electrochemical methods depend on the ability to measure current
flow through the solution, so they have limitations in multiphase or
non-aqueous environments.
Electrochemical methods can identify rapid changes in process
corrosivity, measuring an instantaneous corrosion rate in the system.
Some electrochemical techniques can identify transitions between
active and passive behavior, shifts in polarization by impurities or
additives, and the mechanisms of inhibition. Figure 14.5.
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Figure 14.5 Potentiodynamic Polarization Curve
In addition to limitations in environments which have high
resistivity or where a non-conductive oil phase is present,
electrochemical methods may produce corrosion rate errors when
only a small portion of the surface is corroding by indicating general
corrosion. It may also measure current that does not contribute to
corrosion. This condition is particularly prevalent in environments
in which H2S or other sulfur compounds are present, as these
compounds are easily oxidized and reduced, producing currents that
are not corrosion-related.
Because of these potential difficulties, electrochemically derived
corrosion rates should be compared to corrosion coupon data.
Electrochemical corrosion monitoring methods include:
•
Linear Polarization Resistance (LPR)
•
Potential Monitoring
•
Zero-Resistance Ammetry (ZRA)
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•
Electrical Impedance Spectroscopy (EIS)
•
Electrochemical Noise (EN).
14.3.4 Linear Polarization Resistance
The Linear Polarization Resistance (LPR) method is one of the most
popular electrochemical techniques for corrosion monitoring.
ASTM G59, “Standard Practice for Conducting Potentiodynamic
Polarization Resistance Measurements,”5 mathematically defines
LPR.
The basic relationship is defined by the following formula:
(icorr) = B/Rp
This equation indicates that polarization resistance (Rp) is inversely
proportional to the corrosion current density where B is a
combination of anodic (ba) and cathodic (bc) Tafel slopes:
B = (ba x bc )/[2.303 (ba + bc )]
Often, automated corrosion monitoring equipment uses a constant
(0.12 V/decade) of current for both the anodic and cathodic
polarizations of steel. For this condition, the previous equation
reduces to:
dE/diapp = 0.026/(icorr) = Rp
The inverse relationship between the corrosion rate and the
polarization resistance shows that high values of measured
polarization resistance yield low corrosion rates. LPR provides the
ability to determine corrosion rate vs. time by taking multiple
measurements over short and extended periods, and the data can be
transmitted to a central location using telemetry. Figure 14.6
illustrates an E vs. i plot from an LPR scan of a corroding metal
electrode where the slope of the line is the polarization resistance.
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Figure 14.6 LPR Scan
As mentioned previously, ASTM G96, “Standard Guide for OnLine Monitoring of Corrosion in Plant Equipment,” provides
guidelines for on-line, in-plant corrosion monitoring, using
electrochemical and electronic techniques.
14.3.5 Potential Monitoring
Potential monitoring can indicate if the proper levels of cathodic or
anodic protection are being maintained, or if local changes in
corrosion behavior are occurring. Also, in applications employing
stainless steel alloys, potential monitoring can indicate the
influences of process changes or additives on the corrosion potential
relative to the pitting potential of the material.
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It should be remembered, however, that this is an indirect method of
monitoring. Potential monitoring assesses the risk of corrosion
rather than the actual corrosion rate.
In addition, it requires the use of a stable reference electrode that
can be used in a plant or field environment. When used in the
evaluation of cathodic protection of underground piping and
equipment, compensation for the IR drop of the soil must also be
considered.
14.3.6 Zero Resistance Ammetry (ZRA)
ZRA monitors the flow of current between two electrodes in a
corrosive environment and is used to evaluate galvanic corrosion
between dissimilar metals. The current flow between two electrodes
of dissimilar materials is measured through a zero-resistance
ammeter. The resultant current flow is a measure of the galvanic
corrosion rate, and the value of the corrosion rate in terms of mm/y
or mpy can be obtained by applying Faraday’s Law as discussed
previously. ASTM G71, “Standard Guide for Conducting and
Evaluating Galvanic Corrosion Tests in Electrolytes,”6 provides
methods for applying ZRA in the evaluation of galvanic corrosion.
14.3.7 Electrical Impedance Spectroscopy
(EIS)
Electrical impedance spectroscopy (EIS) uses an AC signal to excite
or perturb a corroding specimen. EIS monitors the electric response
of the metal/environment interface to the applied AC signal over a
frequency spectrum, typically in the range of 5 kHz to 10 kHz to 50
Hz. To cover the entire range, a full EIS scan may take up to two
hours. However, by limiting the range of frequencies, the time
required for corrosion monitoring with EIS can be reduced.
EIS is a relatively new process, and the analysis of the data is fairly
complex. Figure 14.7 shows two common representations of EIS
data. The Nyquist curve illustrates the imaginary and real
components of the impedance, while the Bode curve yields a plot of
impedance vs. the phase angle. The benefit of the technique is that it
allows the separation of the components of the system resistance.
The assumption that total resistance is potential resistance can lead
to errors in more conventional LPR determinations.
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Figure 14.7 Electrochemical Impedance Spectroscopy (EIS)
In environments of low conductivity, the solution resistance can be
separated from the actual polarization resistance using EIS. EIS is
used to examine coated or inhibited materials more effectively than
LPR techniques by determining the fundamental properties of the
surface layers, such as poor resistance and film capacitance. EIS is
also used to evaluate corrosion of steel in concrete structures and
cathodic protection.
Due to the complexity of EIS data, it may be helpful to benchmark
the information with other more common corrosion monitoring
techniques, such as corrosion coupons.
14.3.8 Electrochemical Noise (EN)
Electrochemical noise (EN) monitoring records the naturally
occurring fluctuations in the corrosion potential and current. EN (as
with EIS) is still under technical investigation for accuracy and
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effectiveness. Current noise uses current variations between two
similar working electrodes whereas potential noise is based on
variations in potential between a working electrode and a stable
reference electrode.
EN data is used to identify localized corrosion and to differentiate
conditions where general and localized corrosion may occur. By
definition, however, the technique measures noise—very small
fluctuations in signal nature and strength—which means that it may
interpret extraneous sources of signal noise as variations which may
have nothing to do with the process. Users should be aware of this
characteristic and be very cautious in the use of this technique.
EN is most commonly applied in plant applications in combination
with other electrochemical techniques, such as LPR and EIS, to
monitor dew point problem areas and multiphase environments.
14.3.9 Hydrogen Flux Monitoring
Hydrogen flux monitoring involves the use of intrusive or nonintrusive hydrogen probes to monitor hydrogen absorption by steel.
Steel corrosion commonly produces atomic hydrogen (Ho) as a
byproduct. Ho can either form molecular hydrogen (H2), which
bubbles off the metal surface, or remain in the atomic state, which
can diffuse into the steel. In the presence of sulfur, either form can
produce H2S, which can lead to various problems associated with
wet H2S cracking, such as:
•
Blistering
•
Hydrogen induced cracking (HIC)
•
Stress oriented hydrogen induced cracking (SOHIC)
•
Sulfide stress cracking (SSC).
Intrusive probes, which are often called finger probes, are inserted
into a vessel or pipe section. The probes consist of steel sensing
elements, which have a hollow space inside, connected to a
pressure-sensing device that monitors the buildup of hydrogen
pressure. The rate of hydrogen pressure buildup is proportional to
the severity of hydrogen absorption and, in turn, qualitatively
proportional to the potential for wet H2S cracking.
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Non-intrusive hydrogen probes use an externally applied cell or
patch to monitor the rate of hydrogen egress from the outer surface
of the steel pipe or vessel wall. They use relatively simple sensing
elements, such as pitch and gauge on the outer surface, which trap
hydrogen. More sophisticated probes use an electrochemical cell,
which reacts with the hydrogen as it exits the outer surface of the
steel to produce a current signal. Different applications of hydrogen
probes are illustrated in Figure 14.8.
Figure 14.8 Various Kinds of Hydrogen Probes
Data from hydrogen flux probes commonly use a hydrogen pressure
increase (or vacuum loss) per unit time. Figure 14.9 illustrates
information obtained with a non-intrusive electrochemical cell
probe. The data is presented as an output current vs. time. This
format is generally compatible with modern telemetry techniques
and can be converted to a hydrogen pressure build-up rate.
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Figure 14.9 Electrochemical Hydrogen Probe Current versus Time Plot
Limitations of hydrogen probes include:
•
Non-correlation with weight loss corrosion in wet H2S service
•
Large, periodic swings in data with operating conditions since
the rate of hydrogen diffusion in steel changes rapidly with temperature
•
Errors or delays in reading process transients as well as
decreased performance if internal blisters or cracks form in the
steel
A baseline must be developed for internal (intrusive) probes as well
as external patch probes to make sense of the data for a particular
piece of equipment.
Hydrogen probes do not provide a method for predicting the exact
corrosion rate occurring inside equipment, but do present a good
measure of hydrogen activity, which can be extrapolated to
hydrogen-related problems, such as corrosion, hydrogen
embrittlement, or hydrogen blistering.
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14.4 A Comprehensive Corrosion
Monitoring Program
Corrosion monitoring should be integrated with chemical injection
and inspection for a successful plant corrosion control program.
14.4.1 Corrosion Monitoring Sites
Corrosion monitoring sites should be coordinated with locations of
chemical injection. The distribution of the aqueous phase and the
injected chemicals through the system must also be considered.
Corrosion monitoring sites should be located in areas where:
•
Water will condense, pool, or impinge
•
Temperature variations are prevalent
•
There are concentrations of corrosive species.
Retractable coupons and ER probes are useful only if placed in areas
of potential corrosion. Figure 14.10 illustrates a typical strategy for
corrosion monitoring sites downstream from an atmospheric
distillation column.
Figure 14.10 Setting of Corrosion Probes
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Figure 14.11 shows a comparison of corrosion rates ahead of the air
cooler, before and after a condenser. As one would expect, the
corrosion rate after the condenser is lower due to the removal of
water in the condenser. The location and severity of corrosion may
vary with feedstock components and refinery operating conditions
since these can influence the location and amount of water
precipitated and the amounts of corrosive agents. Therefore, due to
the uncertainty of factors affecting corrosion, ultrasonic inspection,
radiography, and visual inspection should supplement the
information provided by probes at fixed sites.
Figure 14.11 Corrosion Rate versus Time
A method of reducing monitoring sites involves using modern
corrosion monitoring equipment. Figure 14.12 demonstrates a
sophisticated probe with multiple sensor types. In this application,
the temperature of the sensing element can be controlled while
making corrosion measurements.
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Figure 14.12 Corrosion Monitoring System with Multiple On-Line Probes
Figure 14.13 shows readings from the various sensors viewed in
combination, in addition to the temperature data, illustrating
conditions at which corrosion is most severe.
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Figure 14.13 Output from a Flush-Mounted Multiple Probe
Process water samples providing pH data, dissolved metal content,
and chloride, H2S, and ammonia content are valuable sources of
information. Systems downstream from catalytic cracking units
should be analyzed for cyanide to assess the corrosivity of the
system and the potential severity of hydrogen charging and wet H2S
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cracking as well as the need for chemical treatment, water washing,
and/or other process controls.
Corrosion monitoring in overhead systems should include
inspections during turn-arounds, analysis of samples of corrosion
deposits, and placement of corrosion coupons and ER probes to
detect dew point corrosion, in addition to the use of ultrasonic
inspection, radiography, and visual examination.
Effective corrosion monitoring in refinery units is dependent on
identifying corrosion hot spots, which are typically located in:
•
Areas with precipitation of water from the hydrocarbon phase
•
Tower overheads with air-cooled or water condensers
•
The accumulator
•
Water draw-off boot piping
•
Effluent coolers
•
Sites where corrosive contaminants may concentrate or where
corrosive process chemicals are injected.
14.4.2 Corrosion Monitoring in Specific
Process Units
Although the specific needs for corrosion monitoring and the likely
locations for corrosion vary from refinery to refinery according to
the feedstock and process conditions, certain concerns must be
considered for specific refinery units.
14.4.2.1 Atmospheric Distillation Unit (ADU)
In the atmospheric distillation unit (ADU), critical locations for
corrosion monitoring include crude oil preheat exchangers and
piping, the tower, tower overhead, overhead piping, and condensers.
The latter sites are locations of water condensation complicated by
acid chlorides that have not been completely neutralized and/or
inhibited. Corrosion concerns in the ADU vary with the crude being
processed and increase with sour feedstocks.
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14.4.2.2 Vacuum Distillation Unit (VDU)
In the vacuum distillation unit (VDU), corrosion monitoring is
typically employed at sites of condensation of acidic chloride in the
distillate drum boot and the ejector inter-condenser collector drum.
In addition, corrosion monitoring is used for areas susceptible to
naphthenic acid corrosion, such as the VDU preheater, transfer line,
and gas oil circuits, and in regions of condensation found inside of
the column. Figure 14.14 illustrates the recommended monitoring
sites in a crude vacuum distillation unit.
Figure 14.14 Crude Vacuum Distillation Unit and Atmospheric Distillation Unit
14.4.2.3 Fluid Catalytic Cracking Unit (FCCU)
In the fluid catalytic cracking unit (FCCU), corrosion monitoring
sites are located in the fractionator overhead system, effluent piping
of the compressor after coolers, and debutanizer overhead system.
Figure 14.15 illustrates the recommended monitoring sites in a fluid
catalytic cracking unit.
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Figure 14.15 Catalytic Fractionation Unit
14.4.2.4 Amine Treating Unit (ATU)
In the amine treating unit (ATU), corrosion monitoring sites include
the:
•
Regenerator tower and bottoms piping
•
Regenerator reboilers exposed to rich amine and flashing
•
Regenerator overhead condenser/receiver and piping
•
Amine reclaimer where corrosives may concentrate
•
Lean/rich MEA exchanger due to erosional effects.
Figure 14.16 illustrates the recommended monitoring sites in an
amine treating unit.
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Corrosion Monitoring in Refineries
Figure 14.16 Amine Treatment Unit
14.4.2.5 Sour Water Stripper Units (SWSU)
In sour water stripping units (SWSU), corrosion monitoring is
recommended for optimizing the chemical treatment of streams to
protect the overhead condensers. In some cases, replacement of steel
with corrosion-resistant alloys has eliminated the need for corrosion
monitoring and difficult to apply chemical treatment. Figure 14.17
illustrates the recommended monitoring sites in a sour water
stripping unit.
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Figure 14.17 Non-Acidified Sour Water Stripping Unit
14.4.2.6 Sulfuric Acid Alkylation Unit (SAU)
In the sulfuric acid alkylation unit (SAU), corrosion monitoring
sites include:
•
Effluent piping from the deisobutanizer where caustic and inhibitor treatment needs to be monitored
•
Effluent piping from the deisobutanizer reboiler to the debutanizer OLCM
•
Effluent piping from the debutanizer reboiler to the re-run circuit
•
Effluent piping from the depropanizer overhead condenser
where S02 is formed in the tower reboiler.
Figure 14.18 illustrates the recommended monitoring sites in a
sulfuric acid alkylation unit.
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Corrosion Monitoring in Refineries
Figure 14.18 Sulfuric Acid Alkylation Unit
14.4.3 Automated On-Line Monitoring
Automated on-line monitoring is used to minimize unscheduled
downtime and costly equipment failures. It provides a great deal
more information in a shorter time than older, more traditional
methods. However, it is prone to several problems related to:
•
Selection of representative corrosion monitoring sites and monitoring techniques
•
Specification and selection of automated corrosion monitoring
equipment
•
Troubleshooting problems associated with equipment reliability,
telemetry (data links), and signal noise
•
Verification of data (comparison with data from other sources,
such as inspection and coupons)
•
Selection of hardware and database software
•
Training of support personnel
•
Analysis of data, definition of trends, correlation with process
variables/set-ups, and integration with process controls
•
Use of data to make process changes.
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Because of these potential problems, on-line monitoring should be
accompanied with the other techniques described in this chapter to
make certain that the continuous data remains accurate.
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References
1. ASTM G4, “Standard Guide for Conducting Corrosion Coupon Tests in Field Applications” (West Conshohocken, PA:
ASTM, 1995).
2. ASTM G1, “Standard Practice for Preparing, Cleaning, and
Evaluating Corrosion Test Specimens” (West Conshohocken,
PA: ASTM, 1991).
3. ASTM G46, “Standard Guide for Examination and Evaluation of Pitting Corrosion” (West Conshohocken, PA: ASTM,
1994).
4. ASTM G96, “Standard Guide for On-Line Monitoring of
Corrosion in Plant Equipment (Electrical and Electrochemical Methods)” (West Conshohocken, PA: ASTM, 1996).
5. ASTM G59, “Standard Practice for Conducting Potentiodynamic Polarization Resistance Measurements” (West Conshohocken, PA: ASTM, 1997).
6. ASTM G71, “Standard Guide for Conducting and Evaluating
Galvanic Corrosion Tests in Electrolytes” (West Conshohocken, PA: ASTM, 1998).
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Chapter 15:Materials of Construction
for Refinery Applications
Objectives
Upon completing this chapter, you will be able to do the following:
•
Discuss the role of the corrosion engineer in the material selection process
•
Identify and discuss the information and activities required to
adequately define the problem during the material selection process
•
Conduct a return on investment analysis for several possible
material solutions
•
Calculate the corrosion rate, corrosion allowance, and wall
thickness required for a material under consideration for selection
•
Identify the factors that influence the equipment’s service life
•
Identify and discuss the three main categories used to specify
materials of construction for process equipment used in corrosive service
•
Discuss the importance of national standards to the designer
•
Identify the areas that should be addressed when the designer
writes a specification
•
Identify the areas that the designer should address through a
quality assurance program
•
Identify several mechanical, chemical, and physical properties
of metals that make them suitable for refinery applications
•
Identify refinery steels and other metals and alloys used in refinery equipment applications
•
Discuss the significance of killed steels in relation to resisting
corrosion
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•
Compare and contrast the effects of common alloying elements
on steel as well as their principal functions
•
Identify and discuss the five categories of steels used in refinery
applications in terms of corrosion resistance
•
Identify and discuss the four categories of cast irons used in
refinery applications in terms of corrosion resistance
•
Identify and discuss the four types of other metals and their
alloys used in refinery applications in terms of corrosion resistance
•
Identify and discuss the three types of non-metallic materials
used in refinery applications in terms of corrosion resistance
•
Define heat treatment and discuss heat treatment processes,
including normalization, annealing, quenching, stress relieving,
solution heat treatment, and specialized heat treatments
•
Identify the parameters that should be included by the designer
when specifying a complete heat treatment
•
Discuss quality control procedures the designer can specify for
verification of proper heat treatment
•
Compare and contrast preheat treatment of welds and postweld
heat treatment
•
Identify failure mechanisms associated with welding as well as
characteristics inherent to welding that can foster corrosion
•
Compare and contrast welding processes specified by designers
and discuss methods and procedures that are used to assure weld
quality.
15.1 The Role of the Corrosion Engineer
The corrosion engineer has a most significant role in the selection of
materials. His decisions directly affect the efforts of the other
participants in the design, fabrication, installation, and maintenance
of refinery piping and equipment. His choices must consistently
provide satisfactory answers to five types of questions:
1. What are the material’s mechanical properties, such as tensile
strength, fracture toughness, ductility, fatigue strength, hard-
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ness, high/low temperature strength, thermal conductivity,
density, melting point, etc?
2. What is the corrosion resistance to process and atmospheric
environments?
3. What are practical properties, such as availability in the specified form and the capability of being fabricated successfully
by forming, casting, heat-treating, and welding?
4. What is the relative ease of field installation and subsequent
maintenance?
5. What is the economic optimum, considering design life
expectancy, reliability, and life-cycle cost (overall cost/years
of life)?
Unlike predicting answers to most of the questions above,
predicting corrosion resistance is neither precise nor absolute,
particularly in new processes. Here the need for corrosion
engineering experience is critical.
The ultimate measures of the corrosion engineering effort are:
1. Did the equipment perform satisfactorily?
2. Was the overall cost the optimum?
15.1.1 Problem Definition
The first step in the choice of materials should be the collection of
information to define the problem. This information should include
the following:
1.Familiarization with characteristics of the process under consideration, including pressure, temperatures, and composition
of process streams, including trace components.
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2. Identification of very similar processes previously designed
and currently in operation.
3. Identification and analysis of material problems, if any, in
these operating systems. If possible, identify the corrosion
mechanisms associated with the problems.
4. Identification of sources of assistance available including inhouse and outside professional engineers, technical societies,
and publishers of engineering material standards. A specific
source of available corrosion engineering assistance is Materials Performance, a journal published monthly by NACE
International.
Problem definition should also entail:
•
Selection and review of alternative solutions to the anticipated
problems
•
Preparation of a well-defined course of action and schedule to
compare and evaluate the alternate solutions.
In evaluating the alternate solutions, the following should be
compared:
1.Relative vulnerability of each to corrosion attack
2. Safety consequences of failure to personnel and associated
equipment
3. Availability of materials and relative ease of fabrication
4. Requirements for post-fabrication heat treatment
5. Operational reliability
6. Maintainability
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The final step should be calculating the economics associated with
each alternate under consideration. First, material cost is seldom a
sufficient indicator in comparing alternates. Cost comparisons
should include:
• Total material costs
•
Labor costs to install
•
Cost of maintenance and unscheduled shutdowns
•
Replacement costs.
An example of such an evaluation follows in Table 15.1 .
Table 15.1: Return on Investment Analysis
Material/
Solution A
Material/
Solution B
Material/
Solution C
Installed Cost
(Investment)
Additional Cost
Over “A”
Estimated Life
$45,000
$65,000
$60,000
$20,000
$15,000
4 yr.
6 yr.
10 yr.
Estimated Maintenance Rate
Annual Replacement Cost
(Installed Cost
Estimated Life)
Annual Maintenance Cost
(Installed Cost x
Rate)
Total Annual Cost
10%
7%
5%
$11,250
$10,830
$6,000
$4,500
$4,550
$3,000
$15,750
$15,380
$9,000
$370
$6,750
$185
$3,375
0.9%
22.5%
Cost Category
Annual Savings vs.
Cost for “A”
Tax on Savings @
50%
Return on Investment over “A”
(Net Savings
Additional Cost)
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The above example demonstrates that when all factors are taken into
account, the final results bear little relation to initial costs.
Note, however, that a difficulty with this example is the uncertainty
factor connected with the life expectancy estimate. Well designed
plant and laboratory tests may at least give order of magnitude
estimates.
15.2 Corrosion Failures
As discussed in Chapter 1, Corrosion and Other Failures, corrosion
in metals is generally thought to occur according to the
electrochemical concept. This concept holds that the complete
corrosion reaction is divided into an anodic portion and a cathodic
portion occurring simultaneously at discrete points on metallic
surfaces. Flow of electricity from the anodic to the cathodic area
may be generated by local cells set up either on a single metallic
surface (because of local point-to-point differences on the surface)
or between dissimilar metals.
Deterioration
in
non-metallic
materials
is
essentially
physiochemical rather than electrochemical. The deterioration in
plastics and other non-metallic materials is generally swelling,
crazing, cracking, softening, etc. Some of these materials are
deteriorated rapidly in a particular environment; others are
practically unaffected. Under some conditions, a non-metallic
material may show evidence of gradual deterioration. However, it is
seldom possible to evaluate its chemical resistance by weight loss
alone as is generally done for metals.
During the evaluation of materials that may be selected for
construction, the designer must take into account the probable
corrosion mechanisms attributed to the specific process for which
the equipment is being designed. General corrosion is the most
prevalent form of corrosion in refineries. However, corrosion forms
with a lower failure frequency rate must also be considered in the
material selection process. For example, hundreds of general
corrosion failures that gradually leak may be repaired one at a time
without the need for a plant shutdown, while one catastrophic
hydrogen embrittlement failure could result in the immediate
shutdown of an entire plant.
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15.3 Corrosion Testing Methods
The principal types of corrosion tests in decreasing order of
reliability are:
1.Actual operating experience with full-scale plant equipment
exposed to the corroding medium.
2. Small-scale plant experience under commercial or pilot plant
conditions.
3. Sample tests in the field. These include coupons, stressed
samples, and electrical resistance probes exposed to the plantcorroding medium.
4. Laboratory tests on samples exposed to actual plant fluids or
simulated environments.
Obviously, plant or field tests are the most useful for selection of the
suitable alternative materials to withstand a particular environment.
Such tests also permit evaluation of the effectiveness of alternative
means of preventing corrosion, such as the use of inhibitors.
One laboratory test, the total immersion test, can be used to screen
potentially suitable materials for chemical resistance to corrosion.
NACE International provides a complete description of a total
immersion test. A copy of NACE Standard TM0169 (current
edition), “Laboratory Corrosion Testing of Metals” (Houston, TX.,
NACE) is included as Appendix U.
Test results can identify the type of corrosion and data for
calculation of a corrosion rate. An equation for calculating the
corrosion rate follows.
Corrosion Rate = Weight Loss x 534
Area x Time x Metal Density
Units:
Weight loss in milligrams
Time in hours exposed
Area in square inches of metal exposed
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Metal density in grams per cubic centimeter
Obviously, use of this calculated corrosion rate should recognize
and make allowance for the type of test and the type of corrosion
observed.
Assuming the validity of the calculated corrosion rate, it can be used
to calculate a corrosion allowance and the resulting wall thickness
required.
Example:
For mechanical considerations:
Wall thickness = 3/16 in.
Corrosion rate = 15 mils/year
Expected life of equipment = 10 years
Total corrosion allowance =
0.015 in. (corrosion rate per year) x 10 years = 0.15 in.
Final wall thickness required =
0.15 in. + 0.1875 = 0.3375 in.
Wall thickness specified = 3/8 in. (0.3375 in.)
The thickness specified, 3/8 in., is the closest standard plate
thickness available.
15.4 Materials Selection Approach
The selection of the proper material of construction is an important
part of the designer's job and is the one factor that is generally
emphasized. However, consider all of the following factors that
influence the equipment's service life, which are:
•
Selection of materials of construction
•
Design details
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•
Specification of materials
•
Fabrication and inspection
•
Process operation
•
Maintenance (cost and frequency).
15-9
These factors, which influence the equipment’s service life, should
always be kept in mind by the designer. For instance, for the best
equipment or structural design, the materials of construction must
be carefully selected from a corrosion-resistance standpoint.
The design details should preserve the corrosion resistance of the
materials. Concise and clear written specifications should be
provided to the supplier to ensure that the required material is
accurately ordered. The equipment should be fabricated properly
and adequately inspected to prove compliance with the
specifications.
Operating the equipment within the specified design parameters is a
factor that is sometimes overlooked. Plants may change a process
without sufficient regard to the effect of the process change on the
construction materials. The equipment must also be maintained
properly. All of these factors must be considered by the designer to
ensure the expected life of the equipment. When corrosion failures
occur, the selection of the involved materials of construction is
usually faulted. However, in a large number of cases, failure
actually occurred as a result of other factors.
15.4.1 Using Professional Consultants
Many large companies, particularly in the refining industry, have
materials engineering groups comprised of trained engineers who
work directly with designers at company plants to help reduce the
costs associated with corrosion.
Materials engineers have intimate knowledge of the processes and
corrosion problems in their assigned plants and are available to the
designers for consultation on any design problem. The designer, in
turn, must have a basic knowledge of corrosion to recognize when a
potential problem may exist and when to consult a materials
engineering expert. A fundamental obstacle that must be overcome
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is confronting corrosion problems after the plant has been built
rather than while the process is still in the drawing board stage.
Many smaller companies do not have the luxury of in-house
materials engineering groups. Therefore, designers, in many
instances, may have to rely on engineering materials vendors for
advice in the selection of materials of construction, design details,
specifications, etc. There are many materials suppliers who provide
beneficial information on the materials they manufacture, having
conducted many corrosion and mechanical tests on specific
products. They also have knowledge about how well their product
has performed in the field.
However, the designer should exercise caution in acting solely upon
the vendor's recommendations. To be good salesmen, vendors have
to be sold on their own products. For example, the paint salesman
may want to paint over everything, while the stainless steel vendor
may want to make everything out of stainless steel. As a solution to
this problem and to avoid discouraging designers from using
vendors, it is wise to have the designer follow an established
procedure for evaluating different alternatives so that he will have
no doubt about which is the better alternative; in this case, paint or
stainless steel.
15.4.2 Specifying Materials
To assure that the designer will actually receive the materials he
went to so much trouble to select, he must furnish clear, concise
specifications to the supplier, manufacturer, and/or fabricator. If the
order is unclear, the supplier may furnish wrong or inadequate
material.
Materials of construction for process equipment intended for use in
corrosive service are generally specified in the following three
broad categories:
1. Chemical composition and mechanical properties.
2. Method of manufacture and heat treatment when required.
3. Form, dimensional tolerances, and finish.
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Regarding the first category—chemical composition and
mechanical properties—many times the notations killed carbon
steel or fire box quality steel plate have been put on drawings to
serve as complete specifications for the steel required. This kind of
specification is equivalent to writing down automobile on a car
order. The buyer may get a Chevette; and then again, he may get a
Cadillac. Killed steel or fire-box quality steel could be low, medium,
or high-carbon steel, alloyed or not.
An example of the importance of specifying chemical composition
and mechanical properties occurred when welded towers were
ordered and built for an American installation in Mexico. During a
storm, the towers fractured and collapsed. The failure was caused by
brittle welds formed when medium-carbon steel was furnished for
the towers instead of the anticipated low-carbon steel. At welded
areas, the welding heat had raised the areas around the welds above
the lower critical temperature of the steel and, when quenching
occurred in the air, brittle untempered areas were formed that
fractured under the stress of the storm. An adequate material
specification had either not been provided to the fabricator of the
tower, or the fabricator did not fully understand the requirements.
The designer must be sure that all requirements for the specified
material are clearly stated and understood by all concerned.
The second category—method of manufacture and heat
treatment—is also important. The method of manufacturing, such as
welding, brazing, silver-soldering, bolting, riveting, casting,
forging, etc., must be specified because the corrosion resistance of
the equipment ordered will be directly affected by the
manufacturing method. It is also very important that the heat
treatment, when required, is carefully specified, as improper heat
treatment can have very detrimental effects on the corrosion
resistance as well as the strength and ductility of steels.
Within the third category—form, dimensional tolerances, and
finish—it is important to ensure that all dimensions are adequately
specified.
Specifications should include the allowable tolerances for all
dimensions. With respect to corrosion, the wall thickness and
corrosion allowance are probably the most important dimensions.
However, finish can play a significant role in some failure
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mechanisms, such as fatigue and stress corrosion cracking. When
specific finish requirements are specified, acceptable tolerances for
the finish should also be included. For example, if a certain finish is
required for the corrosion resistance of austenitic or chromium
stainless steel equipment, the instructions should be more specific
than a smooth or polished surface is required. Specific surface
roughness dimensions and acceptable tolerances should be
provided.
15.4.3 National Standards
An excellent way for the designer to assure that he will receive the
process equipment from the fabricator as it was designed to reduce
corrosion is to use national standards. National standards actually
represent an agreement between fabricators or suppliers and
customers about what can and should be furnished. These standards
are not permanent since they require periodic reviews that may
result in an amendment, modification, or other change in a particular
standard from year to year.
National standards are valuable to the designer because they:
•
Define what is commercially available together with optional
requirements
•
Provide a convenient reference on company specifications,
drawings, and orders
•
Reduce misunderstandings and minimize disputes
•
Represent a production standard that results in a more uniform
product, fewer varieties, lower inventories, and lower costs.
There are literally hundreds of standards available for use by the
designer. A few of the organizations in the United States that publish
material standards are shown in Table 15.2 .
Table 15.2: U.S. Standards Organizations
Abbreviation
AA
AISI
ANSI
Organization Name
Aluminum Association
American Iron and Steel Institute
American National Standards Institute
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API
ASME
ASTM
AWS
AWWA
CDA
CMA
MTI
NACE
SAE
TEMA
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American Petroleum Institute
American Society of Mechanical Engineers
American Society for Testing and Materials
American Welding Society
American Water Works Association
Copper Development Association
American Cast Metal Association
Materials Technology Institute of the Process Industries
NACE International
Society of Automotive Engineers
Tubular Exchanger Manufacturers Association
Many governments have also developed standards. For instance, the
standards developed by the United States Department of Commerce
acting through the National Institute for Standards and Technology
are frequently used by industry, as are standards issued by the
Ordinance and Materials Departments of the U.S. Navy, U.S. Army,
and U.S. Air Force. These include standard specifications termed
QQS-Federal, MIL-S Army-Navy Aeronautical Specs, and
Aerospace Material Specifications (AMS).
15.4.4 Company Standards
Because of repetitive demand for certain items or special processspecific requirements not completely covered by national standards,
many companies have produced their own standards. There also
may be certain situations companies have to deal with that are not
covered by national standards. Special materials specifications,
welding, and inspection procedures may be required to address
process-specific corrosion problems, such as sulfide stress cracking
or high-temperature hydrogen attack. In small companies, national
standards are sometimes modified to satisfy this need. However,
standards sections are sometimes available in large companies to
help the designer.
In one large chemical company, one group administers company
standards. Thirty-one subcommittees, covering many areas, such as
welding, insulation, plastics, heat exchangers, and protective
coatings, write the specifications and review and update them
periodically. Since these specifications address the unique problems
of a company, they can of course be beneficial to the company
designer.
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15.4.5 What the Designer Should Remember
When Writing Specifications
1.Make specifications as short as possible, but they must clearly
define what is required and at what quality level. The quality
level provides assurance that process equipment will perform
reliably and will not fail prematurely.
2. Avoid vague statements, such as all equipment and piping
after welding must be stress relieved. For example, if this
statement were applied when making field connections, costs
would be raised unnecessarily since stress relieving after
welding is difficult, and threaded connections that require no
welding may be substituted.
3. Do not simply specify that high-quality welds are required
without defining the level of quality required for acceptance.
Failure to fully specify acceptance criteria for weld quality
can lead to confusion and problems. For example, a single
manufacturer produced miles of 3-in. (76-mm) diameter
welded AISI 304L austenitic stainless steel pipes. The original purchase specification required 100% radiography of all
the longitudinal weld seams. When lengths of this pipe were
field welded into fittings, the field welds were radiographed,
which revealed not only the field welds themselves, but short
portions of the longitudinal welds which, in many cases, were
very poor. The pipe was cut out, and the pipe fabricator was
contacted. The fabricator stoutly maintained that his pipe was
x-ray quality, and he pointed to a cabinet full of radiographs.
The radiographs were read and a lot of evidence was found
calling for many rejections and repairs. It was finally disclosed that the pipe fabricator had not viewed any of the
radiographs. He thought that passing the x-rays through the
welds made them x-ray quality! This story is not a fabrication! Luckily, only a small amount of pipe had actually been
field welded, and all the poor welds were identified and the
pipe was rejected.
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4. The designer must not only define the acceptance criteria for
indications that will be cause for rejection, but must specify
the extent of inspection such as 5%, 10%, 33%, or 100% of
the welds.
5. Consider costs when writing specifications. The specification
should not be so restrictive that satisfactory quality material
will be excluded. In addition, specifications should not
restrict the manufacturer to the degree that his costs, and
hence the price, will be unnecessarily high. On the other
hand, the specification must not be so vague that inferior
quality may be allowed.
6. Make safety paramount in any specification. For instance, if
pneumatic testing must be conducted, all welds that can be,
should be inspected before testing. All welds that cannot be
inspected by radiography or ultrasonic testing because of
geometry should be tested with the liquid penetrant or magnetic particle method before testing. (If a break occurs during
pneumatic testing, catastrophic failure of the tested equipment can occur.)
7. Whenever possible, to hold down costs, have the equipment
made with commercially available materials using standard
methods of construction.
8. Before finalizing a specification, have it reviewed by potential fabricators. Many times, a fabricator can suggest ways to
save money because he certainly knows best how to build his
product. Specify primarily how the equipment should perform rather than detailing how the fabricator should build it.
For example, the tray manufacturer rather than the tower
designer normally designs trays or packing in a fractionator
tower. This, of course, assumes that the manufacturer is reliable, competent, and has demonstrated the capability of fabricating products of consistent quality at a competitive cost.
9. Specifically note the tests required to assure quality.
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Materials of Construction for Refinery Applications
10. Carefully note in the specification the equipment that is to
be inspected during its manufacture so that the fabricator can
make provisions for the inspector's visits at the proper time.
11. Do not hesitate to specify a trade name or a catalog number
for a product if that product will do the required job. Again
this, of course, assumes that the manufacturer is reliable,
competent, and has demonstrated the capability of fabricating
products of consistent quality at a competitive cost.
15.4.6 Questions the Designer Should Ask to
Control Quality
A designer who is concerned about corrosion resistance must have
some way to control quality. Otherwise, he may not receive from the
manufacturer the corrosion performance he expects from the
equipment he has designed. His quality control program should be
outlined in the purchase order. Remember that quality can and
should be controlled by the designer.
There are many inspection methods available to the designer, but
before he specifies one or more of these methods, he should answer
the following crucial questions:
•
How corrosive are the process conditions?
•
How toxic are the stream components’ conditions?
•
How susceptible is the material of construction to a specific corrosion form, such as crevice corrosion or stress corrosion cracking, etc.?
•
How sensitive is the corrosion resistance of the material of construction to shifts in chemical composition?
•
What joining method is to be used? How sensitive is the corrosion resistance of the material of construction to the method of
joining, such as welding?
•
How competent is the fabricator? What reputation does he have
for self-inspection? Does he use code-qualified welders? Does
he have a formalized and documented QA/QC system?
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Materials of Construction for Refinery Applications
15-17
•
Is heat treatment required (either for equipment stability or corrosion resistance)?
•
If heat treatment is required, how sensitive are the materials of
construction to the heat treatment?
•
How sensitive was the material of construction to mill operations
when it was originally produced?
•
If welding is to be the joining method, how important is the filler
metal to corrosion performance?
Based on the answers to these questions, a quality assurance
program can be formulated.
As broadly defined by the American Society for Quality Control,
quality is the totality of features and characteristics of a product or a
service that determines its ability to satisfy a given need. This can be
briefly stated as fitness for service.
15.4.7 Fitness for Service
The designer should decide what inspection or qualification
methods are required to assure fitness for service. With this in mind,
the designer should confer with his inspection department, his
technical people, and the potential fabricators to determine which
inspection methods should be specified to assure quality. Inspection
costs money, so care should be taken not to over-inspect, such as on
routine jobs being done by proven, competent fabricators. However,
inspection under other conditions can be thoroughly justified
because of substantial cost savings and elimination of safety
hazards.
15.5 Refinery Materials of Construction
15.5.1 Introduction
Pure metals and their alloys are the primary construction materials
used in petroleum refinery and chemical plant construction. Metals
have excellent mechanical properties. That is, they respond well to
external loads. Some important mechanical properties are:
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Materials of Construction for Refinery Applications
•
Strength—The ability to withstand loads, such as those needed
for refinery equipment pressure containment.
•
Ductility—The tendency to bulge or tear rather than to burst or
break.
•
Toughness—The ability to absorb impact loads without brittle
fracture.
•
Hardness—An indicator of good wear resistance.
•
Elasticity—Slight deformation is recoverable.
•
Creep stability—Low flow rate under load.
Metals also have some excellent chemical and physical properties
independent of load that make them suitable for refinery
applications. They are:
•
Oxidation resistance—For scaling resistance at elevated temperatures.
•
Corrosion resistance—For durability under many adverse refinery environments.
•
High melting points—Necessary for stability at elevated temperatures.
•
Thermal conductivity—Desirable for good heat transfer.
Metals and alloys also have excellent fabrication capabilities,
including:
•
Weldable—For ease of joining and alloy overlaying.
•
Formable—Drawing, bending, upsetting, and rolling.
•
Castable—For making complex shapes.
•
Machinable—Cutting, shearing, and grinding.
•
Heat treatable—Permits change and control of mechanical properties.
Low- and medium-carbon steels are used for at least 80% of all
refinery applications, and process and mechanical designs are often
adjusted to permit their use. For example, process temperatures can
be lowered, hydrocarbon streams can be dried, inhibitors can be
Corrosion Control in the Refining Industry Course Manual
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Materials of Construction for Refinery Applications
injected, or generous corrosion
accommodate the use of carbon steel.
15-19
allowances
provided
to
As refining processes have developed and become more complex,
so have the demands for suitable materials of construction to handle
more severe conditions of temperature, pressure, and corrosivity.
The refinery steels have evolved to meet the majority of refinery
equipment applications. Some of the refinery steels are listed in
Table 15.3 , along with their nominal compositions. Note that there
is an ascending order of alloy additions.
Table 15.3: The Refinery Steels
Alloy
Carbon steel
Carbon-1/2 Mo
1-1/4 Cr-1/2 Mo
2-1/4 Cr-1/2 Mo
5 Cr-1/2 Mo
9 Cr-1 Mo
12 Cr (Type 410)
17 Cr (Type 430)
26 Cr (Type 446)
Type 304 stainless
Type 304L stainless
Type 316 stainless
Type 309 stainless
Type 310 stainless
2-1/4% Nickel steel
3-1/2% Nickel steel
Nominal Composition
0.10%-0.30% C, 0.30%-1.0% Mn, bal. Fe
0.10%-0.20% C, 0.50% Mo, bal. Fe
0.15% C max., 1.25% Cr, 0.5% Mo, bal. Fe
0.15% C max., 2.25% Cr, 1.0% Mo, bal. Fe
0.15% C max., 4%-6% Cr, 0.5% Mo, bal. Fe
0.15% C max., 8%-10% Cr, 1% Mo, bal. Fe
0.15% C max., 11%-13% Cr, bal. Fe
0.12% C max., 14%-18% Cr, bal. Fe
0.20% C max., 23%-30% Cr, bal. Fe
0.08% C max., 18%-20% Cr, 8%-11% Ni, bal. Fe
0.03% C max., 18%-20% Cr, 8%-12% Ni, bal. Fe
0.08% C max., 16%-18% Cr, 10%-14% Ni, 2%-3% Mo,
bal. Fe
0.15% C max., 22%-24% Cr, 12%-15% Ni, bal. Fe
0.15% C max., 24%-26% Cr, 19%-22% Ni, bal. Fe
0.19% C max., 2.03%-2.57% Ni, bal. Fe
0.19% C max., 3.18%-3.82% Ni, bal. Fe
Alloying elements improve the mechanical, chemical, and physical
properties of steel and enable the handling of corrosive fluids over a
wide range of pressures and temperatures. For example, Cr-Mo
steels provide high-temperature strength, resistance to hightemperature sulfur corrosion, and resistance to hydrogen attack.
Stainless steels are used for furnace tubes and to resist hightemperature sulfidic corrosion in the presence of hydrogen. Stainless
steels containing molybdenum are used against naphthenic acid
attack.
Please note, alloying steel does entail additional cost. In addition,
the availability of some alloy steels is less than that for plain carbon
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Materials of Construction for Refinery Applications
steel. Also, alloy steels may have problems specific to the type of
alloy, such as reduced weldability, susceptibility to environmental
cracking, and specialized heat treatment requirements.
Other metal and alloy systems that are important in refinery
construction are copper-, nickel-, aluminum-, and titanium-based
alloys. Table 15.4 shows these commonly used metals and alloys
along with compositions and principal applications.
Table 15.4: Other Refinery Metals and Alloys
Alloy Group
Aluminum Alloys
Alloy 110
Alloy 3003
Alloy 6061
Alclad
Copper Alloys
Copper
Inhibited admiralty
Naval brass
Aluminum brass
70-30 Copper-Nickel
90-10 Copper-Nickel
Other Materials
Titanium
Monel
Alloy 800
Alloy 20
HF-Modified A29767 (cast)
Supertherm
Nominal Composition
Application
99% Al
1.0%-1.5% Mg, bal. Al
0.8%-1.2% Mg, 0.4%-0.8% Si, bal. Al
Pure Al applied over other material
Light structural
Exchanger tubing
Heat treatable, plate,
rod
Cathodic protection
99% Cu
28% Zn, 1% Sn, 71% Cu, (Sb, P, As)
39% Zn, 1% Sn, 60% Cu
22% Zn, 2% Al, 76% Cu
70% Cu, 30% Ni
90% Cu, 10% Ni
Tubing
Condenser tubing
Tubesheets
Condenser tubing
Tubing, plate
Tubing
99% Titanium
70% Ni, 30% Cu
30%-35% Ni, 19%-23% Cr, 40% Fe,
0.10% C
28%-30% Ni, 19%-21% Cr, 4% Cu, 3%
Mo, bal. Fe
0.15%-0.20% C, 21%-25% Cr, 6.5%10% Ni
0.5% C, 26% Cr, 35% Ni, 15% Co, 5%
W
Tubing
Tubing, plate
Pipe, tubing, plate
Pipe, tubing, plate
Heater tubes, piping
Heater tubes
As mentioned previously, refinery materials selection is a balance
between safety, performance, and cost. Due to the hazardous nature
of materials processed by the refining industry, safety considerations
demand exceptional equipment integrity. The following information
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Materials of Construction for Refinery Applications
15-21
will describe the principal refinery metals and alloys along with
typical applications.
15.6 Killed Steel
A frequently encountered term in steel terminology is killed steel.
This term is given to steel produced by a practice begun early in the
steel industry. While the molten steel was still in the furnace just
prior to being poured into a mold, a deoxidizing agent was added to
remove gases, such as carbon dioxide, which would otherwise
evolve violently from the melt as it was being poured into the mold.
Addition of the deoxidizing agent resulted in quieting the pouring
operation. The melt would lie quietly in the mold; hence, the term
killed steel. Subsequently, with increased knowledge of the steel
making process and of the resultant products, it was realized that
this step in steel making had the very beneficial result of making the
product more uniform in chemical composition and properties. One
important result was the production of steel products with greater
uniformity in resistance to corrosive attack.
There are variations of the process, which are termed semi-killed
steel, rimmed steel, and capped steel. These variants achieve only
partially (or not at all) the results of fully killed steel. The
uniformity of composition resulting from the latter is the overriding
and sought-after benefit from a corrosion resistance standpoint.
15.6.1 Steels
Steel—iron alloyed with carbon and manganese—is the
predominant material for refinery construction. It provides the
desired mechanical, chemical, and physical properties at a
reasonable cost. Steels are readily available in many forms and have
excellent fabrication capabilities. The weldability of steel is
excellent, which contributes greatly to the reliability and safety of
modern day, pressure-containing equipment.
Steel is a general term for iron-based alloys containing carbon,
manganese, and other alloying elements. Table 15.5 shows some of
the common alloying elements, their effects in steel, and their
principal functions. The carbon content of most refinery steels is
between 0.03% to 0.30% to assure ductility and weldability.
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Materials of Construction for Refinery Applications
Table 15.5: Some Specific Effects of Alloys in Steel
Element
Influence on
Ferrite
Influence on
Carbide
Austenite
Forming
(Hardenability
Tendency
)
Moderately
Greater than
increases hard- Mn; less than
enability, simi- W
larly to
manganese
Chromium (Cr)
Hardens markedly; increases
corrosion resistance
Manganese
(Mn)
Hardens markedly; reduces
plasticity somewhat
Moderately
increases hardenability, similarly to
chromium
Greater than Fe;
less than Cr
Molybdenum
(Mo)
Provides agehardening system in high MoFe alloys
Strongly
increases hardenability (MoCr)
Strong; greater
than Cr
Nickel (Ni)
Strengthens and
toughens by
solid solution
Mildly
increases hardenability, but
tends to retain
austenite with
higher carbon
Less than Fe
(graphitizes)
Phosphorus (P)
Hardens
strongly by
solid solution
Increases hardenability similarly to
manganese
Nil
Corrosion Control in the Refining Industry Course Manual
Principal
Functions
Increases corrosion and oxidation resistance;
adds some
strength at high
temperatures
Counteracts
brittleness from
the sulfur;
increases hardenability inexpensively
Deepens hardening; improves
hot and creep
strength and
corrosion resistance in stainless steel
Strengthens
unquenched or
annealed steels;
toughens pearlitic-ferritic
steels (especially at low
temperature)
and renders
high chromiumiron alloys austenitic
Strengthens low
carbon steels;
increases resistance to corrosion
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15-23
Silicon (Si)
Hardens with
loss in plasticity
(Mn-Si-P)
Increases hardenability more
than nickel (NiSi-Mn)
Negative
(Graphitizes)
Titanium (Ti)
Provides agehardening system in high TiFe alloys
Probably
increases hardenability very
strongly, as dissolved. Its carbide effects
reduce hardenability.
Greatest known
(2% Ti renders
0.50% carbon
steel unhardenable.)
Used as general purpose
deoxidizer;
improves oxidation resistance and
strengthens
low-alloy steels
Fixes carbon in
inert particles;
prevents localized depletion
of chromium in
stainless during
long heating
Steels for refinery applications fall within the following categories.
•
Carbon steels
•
Low-alloy steels
•
Cr-Mo steels
•
Stainless steels
•
Nickel steels.
In the United States, most of these types of steel are covered by the
chemistry and/or property specifications of one or more of the
following organizations:
•
American Society for Testing and Materials (ASTM)
•
American Society of Mechanical Engineers (ASME)
•
American Petroleum Institute (API)
•
American Iron and Steel Institute (AISI)
•
American National Standards Institute (ANSI).
In other countries, other standards organizations may be utilized.
Most specifications embrace a variety of products or grades, and
these subtypes represent variations in chemistry, method of
manufacture, and mechanical properties.Table 15.6 shows some of
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Materials of Construction for Refinery Applications
the ASTM specifications applicable to tubular products, plates,
casting, and forgings.
Table 15.6: ASTM Standard Specifications for Refinery Steels
Material
Carbon Steel
C-1/2 Mo Steel
1 Cr-1/2 Mo
Steel
1-1/4 Cr-1/2
Mo Steel
2 Cr-1/2 Mo
Steel
2-1/4 Cr-1 Mo
Steel
Pipes and
Tubes
A53, A106,
A134, A135,
A139, A178,
A179, A192,
A210, A214,
A226, A333,
A334, A369,
A381*, A524,
A587, A671,
A672, A691
A209, A250,
A335, A369,
A426, A672,
A691
A213, A334,
A369, A426
A213, A335,
A369, A426,
A691
A213, A369
A213, A335,
A369, A426,
A691
3 Cr-1 Mo Steel A213, A335,
A369, A426,
A691
5 Cr-1/2 Mo
A213, A335,
Steel
A369, A426,
A691
7 Cr-1/2 Mo
A213, A335,
Steel
A369, A426
9 Cr-1 Mo Steel A213, A335,
A369, A426
Plates
Castings
Forgings
A283, A285,
A299, A455,
A515, A516,
A537, A570,
A573
A27*, A216,
A352
A105, A181,
A234, A268,
A350, A372,
A420, A508,
A541
A204, A302,
A517, A533
A217, A352,
A487
A182, A234,
A336, A508,
A541
A387, A517
A182, A234,
A336
A182, A234,
A336, A541
A387, A389*,
A517
A217, A389*
A387, A542
A217, A487
A182, A234,
A336, A541,
A542
A182, A336
A217
A182, A234,
A336
A387
A387
A387
A387
Corrosion Control in the Refining Industry Course Manual
A182, A234
A217
A182, A234,
A336
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Materials of Construction for Refinery Applications
Ferritic, Martensitic, and
Austenitic
Stainless Steel
A213, A249,
A268, A269,
A312, A358,
A376, A409,
A450, A451,
A511*
A167, A176*,
A240, A412
15-25
A297*, A351,
A447*
A182, A336,
A403, A473*
Note: Carbon and alloy steel bolts and nuts covered by Specifications A193, A194,
A320, A354, A449, A453, A540, and A563*.
*These specifications are not approved by the ANSI/ASME Boiler and Pressure Vessel
Code.
The ASTM Standards listed in the table are referenced in numerical order beginning on
Page 3:65.
The code or standard to which a piece of equipment is constructed
normally specifies the materials standards to be followed and the
design stresses that can be used. In the United States the most
common design codes for refinery equipment are those of ASME,
ANSI, and API.
15.6.2 Carbon Steel
Carbon steel is iron containing controlled amounts of carbon and
manganese. The carbon steels are among the most common
materials of construction and probably account for 80% of all steels
used for refinery applications. Since they are typically welded,
carbon content must be relatively low, between 0.15% and 0.35%,
and they are commonly termed low- or medium-carbon steel.
Distillation towers, separators, heat exchangers, storage tanks, most
piping, and all structures are generally fabricated from carbon steel.
For processes where the expected corrosion rates for carbon steel
are <20 mpy, economic analysis will normally favor carbon steel at
temperatures below 800F (426C).
When carbon steel is not suitable because of corrosion, it can be
lined or coated with other materials that offer better corrosion
resistance. For large vessels, alloy-clad or alloy-weld overlay are
effective forms of lined construction and more economical than the
use of solid corrosion-resistant alloys throughout. The application of
spray-applied coatings, both metallic and non-metallic, also
provides a cost-effective method of improving the corrosion
resistance of carbon steel.
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Materials of Construction for Refinery Applications
15.6.3 C-Mo Steels
C-Mo steels, primarily the C-1/2 Mo grade, exhibit improved hightemperature strength and creep resistance over carbon steels,
especially at temperatures between 800F and 1000F (426C and
538C). However, molybdenum addition provides no significant
increase in corrosion resistance over carbon steels. In the past, it had
been believed that C-1/2 Mo steel had better resistance than carbon
steel to high-temperature hydrogen attack, and it was often specified
in hot hydrogen service. However, questions have been recently
raised regarding the effect of long-term exposure to hightemperature hydrogen on C-1/2 Mo steel. As a result, Cr-Mo steels
are typically used instead of C-1/2 Mo for most new refinery
equipment fabrication.
15.6.4 Low-Alloy Steels
Low-alloy steels contain 1% or less chromium, nickel,
molybdenum, vanadium, and copper, in various ratios. In the U.S.,
the standard compositions of these steels are specified in the ANSI
or SAE standards. Two of these low-alloy steels, 4140 and 4340, are
commonly utilized in refineries. They are steel with chromium,
nickel, and molybdenum additions.
These materials exhibit good high-temperature strength and creep
resistance. However, since they normally have relatively high
carbon equivalents (>0.4), they can be difficult to weld. Therefore,
the use of low-alloy steels is normally limited to those applications,
which do not require fabrication by welding. Also, these materials
tend to display high hardness and are susceptible to sulfide stress
cracking if hardness exceeds HRC 22. Low-alloy steels are
commonly used in refineries for flange bolts, valve parts, and shafts
or rods in pumps and compressors.
Some specialized grades of low-alloy steels known as HSLA (HighStrength, Low-Alloy) steels are commonly used for high-pressure
gas transmission pipelines. HSLA steels have their chemistry
controlled to allow fabrication by welding.
15.6.5 Cr-Mo Steels
Cr-Mo steels are alloys containing up to 10% chromium and a few
percent or less of molybdenum, copper, or vanadium. Early attempts
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Materials of Construction for Refinery Applications
15-27
to combat high-temperature sulfur corrosion in refineries involved
the use of straight chromium steels. Although these steels originally
had satisfactory ductility, prolonged service produced temper
embrittlement. The addition of 0.5% molybdenum to 1%
molybdenum into the straight chromium steels was found to be an
effective solution for this problem.
From a design point of view, the low-alloy steels containing up to
9% chromium and 1% molybdenum are generally more cost
effective than carbon steel at temperatures above 900F (482C).
Aside from the stainless steels, Cr-Mo steels are the only steels
which are rated to 1200F (648C), in terms of allowable stresses by
the ASME Pressure Vessel and ANSI Piping System Codes.
Cr-Mo steels with less than 4% chromium provide only a modest
increase in corrosion resistance over carbon steels. These materials
are normally specified for applications where high-temperature
strength, creep resistance, and/or resistance to high-temperature/
high-pressure hydrogen attack are required.
The highest creep strengths are obtained with steels containing 1/2%
or more molybdenum. It is not surprising to find, therefore, that 1-1/
4 Cr-1/2 Mo and 2-1/4 Cr-1 Mo steels are widely used in refineries
for reactor vessels which operate at high temperatures and
pressures. For improved corrosion resistance, these are usually clad
or weld-overlayed with austenitic stainless steels.
The 5% to 9% Cr-Mo steels provide good corrosion resistance to
high-temperature sulfur corrosion when required, as in refineries
processing sour crude oils. These materials have found extensive
use in refineries for this application.
15.6.6 Nickel Steels
Nickel steels contain 1% to 9% nickel and have significantly greater
low-temperature toughness compared to carbon steel. The 2-1/4 Ni
and 3-1/2 Ni steels have been used for low-temperature refinery
processes, such as propane refrigeration systems. With proper
procedures and filler metals, these steels can be welded so that the
weldment impact properties approach those of the alloyed base
metal. The use of nickel steels in refineries is generally limited to
processes operating below -50F (-45.5C).
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Materials of Construction for Refinery Applications
15.6.7 Stainless Steels
Stainless steels are alloyed with at least 11.5% chromium to become
stainless. Chromium promotes the formation of passive iron/
chromium oxide films on steel which, in turn, exhibit excellent
corrosion resistance. Many different grades of stainless steels are
available and their cost, mechanical properties, and corrosion
resistance vary considerably. It is important, therefore, that stainless
steels be carefully selected to match the specific service intended.
Various grades of stainless steels (wrought alloys) used in refineries
are listed in Table 15.7 Cast alloy compositions differ somewhat
from the AISI types shown.
Table 15.7: Chemical Composition of Principal Stainless Steels
AISI Type
%C
%Cr
%Ni
410 (Martensitic)
416 (Martensitic)
431 (Martensitic)
440A (Martensitic)
405 (Ferritic)
430 (Ferritic)
442 (Ferritic)
446 (Ferritic)
0.15
max.
0.15
max.
0.20
max.
0.6-0.75
11.513.5
12-14
15-17
16-18
--1.252.5
--
-Se/Mo/ Zr
---
Equivalent
Cast Alloy
CA-15
-CB-30
--
0.08
max.
0.12
max.
0.25
max.
0.20
max.
11.514.5
14-18
18-23
23-27
0.5
max.
0.5
max.
0.5
max.
0.5
max.
0.1-0.3 Al
--0.25 N max.
---CC-50, HC
Corrosion Control in the Refining Industry Course Manual
% Other
Elements
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Materials of Construction for Refinery Applications
301 (Austenitic)
302 (Austenitic)
304 (Austenitic)
304L (Austenitic)
308 (Austenitic)
309 (Austenitic)
309S (Austenitic)
310 (Austenitic)
310S (Austenitic)
316 (Austenitic)
316L (Austenitic)
317 (Austenitic)
317L (Austenitic)
321 (Austenitic)
347 (Austenitic)
17-7 PH (AgeHardenable)
17-4 PH (AgeHardenable)
15-29
0.15
max.
0.15
max.
0.08
max.
0.03
max.
0.08
max.
0.20
max.
0.08
max.
0.25
max.
0.08
max.
0.08
max.
0.03
max.
0.08
max.
0.03
max.
0.08
max.
0.08
max.
0.07
16-18
17-19
18-20
18-20
19-21
22-24
22-24
24-26
24-26
16-18
16-18
18-20
18-20
17-19
17-19
6-8
8-10
8-12
8-12
10-12
12-15
12-15
19-22
19-22
10-14
10-14
11-14
11-14
8-11
9-13
2 Mn max.
2 Mn max.
1 Si max.
1 Si max.
1 Si max.
1 Si max.
1 Si max.
1.5 Si max.
1.5 Si max.
2-3 Mo
2-3 Mo
3-4 Mo
3-4 Mo
Ti: 4 x C min.
Cb + Ta: 10 x
C min.
-CF-20
CF-8
CF-3
-CH-20, HH
-CK-20, HK
-CF-8M, CF12M
CF-3M
CG-8M
--CF-8C
17
7
1 Al
--
0.05
16.5
4.2
4 Cu
--
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E-Brite (Specialty)
Al 29-4-2 (Specialty)
329 (Specialty)
3RE60 (Specialty)
SAF-2205 (Specialty)
904L (Specialty)
Materials of Construction for Refinery Applications
0.002
0.005
26
29
0.1
2
1 Mo, 0.1 Cb
4 Mo, 0.13 N
---
0.08
max.
0.03
max.
0.03
max.
25
18.5
22
3.5
4.5
5.5
----
20
25
Mo
2.7 Mo, 1.7 Si
3 Mo, 0.8 Si,
0.14 N
4 Mo, 1.5 Cu
--
0.02
Stainless steels can be classified in the following categories.
•
Martensitic stainless steels
•
Ferritic stainless steels
•
Austenitic stainless steels
•
Duplex stainless steels
•
Precipitation hardening stainless steels
•
Specialty stainless steels.
15.6.7.1 Martensitic Stainless Steels
Martensitic stainless steels, such as type 410 and type 440, can be
hardened by heat treatment similar to carbon, low-alloy, and Cr-Mo
steels. Hardening increases strength and decreases ductility. These
stainless steels are less corrosion resistant than ferritic and austenitic
stainless steels. Martensitic stainless steels contain 11% to 18%
chromium and are relatively high in carbon content. They are
subject to embrittlement at temperatures of 885F (474C) and must
be used with caution above approximately 700F (371C).
Martensitic stainless steels are magnetic, difficult to weld, and will
pit in the presence of chlorides. Sulfide stress cracking (SSC) can be
a problem with martensitic grades hardened above Rockwell C22
(HRC 22). Welds normally require stress relieving to meet this
hardness requirement. Typical refinery applications include pump
components, fasteners, valve trim, turbine blades, and tray valves
and other tray components in distillation towers. Type 410 linings
are often used to protect towers, heat exchangers, and other pressure
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vessels against high-temperature sulfide corrosion in desulfurization
units.
15.6.7.2 Ferritic Stainless Steels
Ferritic stainless steels, such as type 405, type 409, type 410S (12%
Cr), type 430 (17% Cr), and type 446 (26% Cr), are low in carbon
but can be hardened by heat treatment. However, type 405 contains
an aluminum addition that effectively retards its ability to harden
during welding. As a result, type 405 is a better choice than type 410
for vessel linings, especially if clad repairs become necessary during
the vessel's service life.
The ferritic stainless steels are not normally subject to SSC, are
resistant to chloride stress corrosion cracking, and have good
oxidation and sulfidation resistance. All ferritic stainless steels with
chromium content above 11% are subject to embrittlement at a
temperature of 885F (474C), which limits their use to applications
in which temperatures do not exceed 700F (371C). Highchromium stainless steels, such as type 430, are also susceptible to
pitting from wet sulfides in the presence of air during shutdown
conditions.
15.6.7.3 Austenitic Stainless Steels
Austenitic stainless steels, commonly referred to as the 300 series or
18-8 chromium-nickel alloys, have excellent corrosion resistance
and good high-temperature properties. However, they are subject to
pitting corrosion and stress corrosion cracking in the presence of
chlorides. Their use in refineries is limited to applications where
aqueous corrosion can be ruled out. Austenitic stainless steels
cannot be hardened by heat treatment or during welding, which has
encouraged their use in place of 5% chromium and 9% chromium
steels to avoid the need for postweld heat treatment. Like the ferritic
stainless steels, they can be hardened to some degree by cold
working. The most common and readily available grades are types
304, 304L, 304H, 316, 316L, 316H, 317, 321, 321H, 347, and
347H.
The low-carbon grades (designated by L or ELC) are required for
optimum corrosion resistance when welding is to be done. The low
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carbon content of L grades (below 0.03%) minimizes the
precipitation of chromium carbides at the grain boundaries (called
sensitization) which can lead to various forms of intergranular
corrosion in certain applications. Selecting chemically stabilized
grades, such as type 321 and type 347, can also minimize
sensitization. In these grades, alloying with titanium or columbium
(niobium), respectively, prevents the formation of chromiumdepleting carbides.
The high-carbon grades (designated by the H suffix) are normally
specified for applications where additional high-temperature
strength and creep resistance are required, such as high-temperature
(>1200F [648C]) furnace tubes. The H grades are more
susceptible to sensitization than the regular or low-carbon grades,
and special welding procedures may be required to resist
intergranular corrosion.
Type 316 and type 317 stainless steels are two popular grades of
austenitic stainless steels that contain 2% to 3% and 3% to 4%
molybdenum, respectively, and have superior resistance to pitting
corrosion and acids. They also contain greater amounts of nickel,
which results in general corrosion resistance superior to type 304.
Type 316 is also available in cast form (CR-8M). These steels are
commonly utilized for resistance to naphthenic acid corrosion in
refineries that process naphthenic crudes.
Type 309 (25 Cr-12 Ni) and type 310 (25 Cr-20 Ni) are austenitic
grades commonly used where high-temperature oxidation resistance
is desired. These wrought grades and their cast forms (CH-20, HH
40, CK-20, HK 40) are found in fired heaters as tube supports and
hangers.
Typical refinery applications for austenitic stainless steels include
high-temperature processes containing both sulfur and hydrogen,
such as desulfurization and hydrocracking. They are commonly
used in heater tubes, heat exchanger tubing, piping, tower trays,
reactor internals, and as vessel linings in hydroprocessing units. The
austenitics are also used in gas treating units to resist corrosion from
H2S and CO2. The molybdenum grades type 316 and type 317 are
often specified for heater tubes, transfer lines, and tower internals in
units processing naphthenic
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acid-containing crude and gas oils. Caution must always be
exercised when considering austenitic stainless steels in aqueous
environments and in cooling water systems because of the
danger of pitting and stress corrosion cracking from chlorides.
15.6.7.4 Precipitation Hardening Stainless Steels
Precipitation hardening stainless steels, such as 17-4 PH, 17-7 PH,
and 15-5 PH, have application in refinery rotating machinery where
both corrosion resistance and strength are needed. These stainless
steels can be hardened and strengthened by solution quenching,
followed by a precipitation aging treatment at 800F to 1100F
(426C to 593C). They can be easily machined while in the
solution-quenched condition and then aged at temperatures that
minimize scaling, distortion, and cracking. Tensile strengths as high
as 200,000 psi can be obtained.
Precipitation hardening stainless steels are used for valve seats,
pump shafts, pump wear rings, and impellers. Their corrosion
resistance is worse than that of type 304 stainless steel. Also, due to
their high tensile strengths, these materials tend to be highly
susceptible to stress corrosion cracking caused by sulfides and/or
chlorides.
15.6.7.5 Duplex Stainless Steels
Duplex stainless steels have a microstructure composed of almost
equal amounts of ferrite and austenite. Some alloy designations are
AL6XN, 2205, 3RE60, 2304, and Ferralium 255. The typical
composition for duplex alloys is 18% to 30% chromium, 3% to 7%
nickel, and 1% to 3% molybdenum. The ferrite phase offers high
strength, and the austenite phase contributes good corrosion
resistance.
When welding parameters are carefully controlled, duplex stainless
steels have adequate weldability. They have good general corrosion
resistance and are also resistant to chloride stress corrosion cracking
and sulfide stress cracking, provided proper welding and heat
treatment procedures are followed. The duplex stainless steels are
normally proprietary alloy compositions; each developed by a
specific steel manufacturer. Therefore, the steel manufacturer
should always be consulted to determine the correct forming,
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Materials of Construction for Refinery Applications
welding, and heat treatment requirements for each of these
materials.
15.6.7.6 Specialty Stainless Steels
Specialty stainless steels are available to meet severe service
conditions and fill the gaps where the corrosion resistance of
common stainless steels may be marginal. Some of these materials
include austenitic alloys 20 Cb-3, 904L, and 254SMO; and ferritic
alloys SeaCure, E-Brite 26-4, Monit, and 29-4-2. Often these
specialty stainless steels contain significant molybdenum additions
to decrease pitting and crevice corrosion.
The specialty stainless steels are normally proprietary alloy
compositions, each developed by a specific steel manufacturer.
Therefore, the steel manufacturer should always be consulted to
determine if the corrosion resistance to the specific process is
adequate and to determine the correct forming, welding, and heat
treatment requirements for each of these materials.
15.6.8 Cast Irons
15.6.8.1 Gray Cast Irons
Gray cast irons contain 3% carbon and 1.5% silicon, with most of
the carbon in flake form. Because of its inherent brittleness and low
strength, gray cast iron is susceptible to damage by thermal and
mechanical shock. Although once commonly used for many
refinery applications, it is no longer specified for hydrocarbon
services within unit boundaries. Exceptions are pump and valve
components, ejectors, strainers, and some fittings where high
hardness is needed to reduce the velocity effects of corrosion, such
as impingement, erosion, and cavitation. The excellent damping
properties of gray cast iron lead to its continued use in machinery
bases. Although somewhat repairable by special welding
techniques, gray cast iron is generally considered non-weldable for
pressure-containing component repairs.
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15.6.8.2 Ductile Irons
Ductile iron, also called nodular cast iron, has replaced gray cast
iron in valve, pump, and compressor pressure-containing
components. The carbon is present as nodules, which promote
ductility. It has substantially better toughness than gray cast iron but
is usually repaired by welding.
15.6.8.3 High-Silicon Cast Irons
High-silicon cast irons are gray cast irons containing at least 14%
silicon. These cast irons are extremely corrosion resistant due to a
passive SiO2 surface layer, which forms during exposure to many
chemical environments. Duriron is a straight high-silicon cast iron
containing about 14.5% silicon, 1% carbon, and up to 15%
manganese. Durichlor 51 also contains 4% to 5% chromium for
increased resistance to hydrochloric acid in the presence of
oxidizing compounds. Superchlor is vacuum melted Durichlor 51
and possesses twice its tensile strength. High-silicon cast irons are
not machinable and can be shaped only by grinding. These materials
are commonly considered to be non-weldable.
15.6.8.4 Nickel Cast Irons
Nickel cast irons typically contain 13% to 36% nickel and up to 6%
chromium. Known as Ni-Resist, these austenitic alloys are the
toughest of the cast irons. They are also produced as ductile irons,
with high strength and ductility over a wide temperature range. All
have excellent corrosion, wear, and high-temperature resistance due
to the relatively high alloy content. Ni-Resist alloys can be
machined to close tolerances. Typical refinery uses are valve
components, pump components, dampers, diffusers, tray
components, and engine and compressor parts.
15.6.9 Other Metals and Alloys
15.6.9.1 Copper and Its Alloys
Copper and its alloys combine excellent corrosion resistance with
good thermal conductivity, ease of machinability, and good strength,
especially when alloyed. Copper is a relatively noble metal and is
usually not corroded unless oxygen or other oxidizing agents are
present. Copper alloys are especially resistant to aqueous corrosion
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in both fresh and saltwater and are commonly used for heat
exchanger tubes. Copper alloys experience significant loss of
strength above 400ºF (204C) and also offer poor resistance to
sulfide corrosion above this temperature.
One of the more common copper alloys used in refineries is
admiralty brass, a copper alloy containing 28% zinc and 1% tin,
with trace amounts of antimony, arsenic, or phosphorous added for
improved resistance to corrosion. It provides good resistance to
brackish and saltwater corrosion and wet H2S corrosion. Admiralty
tubes have been used extensively in water-cooled condensers and
coolers. Like most copper alloys, admiralty brass is susceptible to
dealloying and has been shown to stress corrosion crack when
exposed to aqueous ammonia solutions.
Aluminum bronze, 90-10 cupro-nickel, and 70-30 cupro-nickel are
other copper alloys often used in refinery applications.
15.6.9.2 Nickel Alloys
Nickel is an important alloy constituent of many corrosion-resistant
materials, including the austenitic stainless steels. The stress
corrosion cracking resistance of austenitic stainless steels rapidly
increases as the nickel content is increased above 20%. For
example, Inconel 600 (a 70% Ni-Cr-Fe alloy) shows excellent stress
corrosion cracking resistance and is used for this reason in many
refinery applications. Nickel also forms the basis for many hightemperature alloys, but nickel alloys can be attacked and embrittled
by sulfur-bearing gases at elevated temperatures.
Various nickel alloys used in refineries are listed in Table 15.8
Monel 400 (a Ni-Cu alloy) is used extensively as a lining in the top
of crude oil distillation towers and as the upper four or five trays to
resist hydrochloric acid. It is also used for crude tower overhead
condenser tubes and components. In addition, Monel 400 is used to
combat corrosion caused by hydrofluoric acid in alkylation units
and in hydrodesulfurization and reforming unit overhead systems.
High-nickel alloys, including Inconel 625 and Incoloy 825, are used
to prevent polythionic acid corrosion of flare stack tips and in
hydroprocessing effluent piping. Hastelloy B-2 is particularly well
suited for handling hydrochloric acid at all concentrations and
temperatures, including boiling point temperatures. It is, however,
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attacked in the presence of oxidizing salts. Alloys B-2 and C-276
have excellent resistance to all concentrations of sulfuric acid up to
temperatures of at least 200F (93C). High-nickel alloys are
expensive, and their use is restricted to applications having
unusually severe corrosion problems.
Table 15.8: Chemical Composition of Principal Nickel Alloys
%Fe
%Co
%W
66
66
76
60
32
42
%M
o
---9
-3
1.4
0.9
8
5
47
30
-------
-------
1
15
16
67
54
61
28
16
16
2
5
3
1
2.5
2
-4
--
% Other
Elements
31 Cu
29 Cu, 3 Al
0.2 Cu
3.6 Cb + Ta
0.3 Cu
1.8 Cu, 0.15
Al, 0.9 Ti
-0.4 V
0.7 Ti
20
29
2
44
--
--
3 Cu
Alloy
%C
%Cr
%Ni
UNS N04400
Alloy K500
UNS N06600
UNS N06625
UNS N08800
UNS N08825
0.15
0.15
0.08
0.1
0.04
0.03
--16
21
20
21
UNS N10665
UNS N10276
UNS N06455
0.02
0.02
0.01
5
0.05
Alloy 20
15.6.9.3 Aluminum
Aluminum, a highly reactive metal, develops oxide films that
protect it against corrosion. These oxide films can be improved by
anodizing. They tend to break down, however, at pH values below 5
and above 8, which limits the use of aluminum and its alloys in
many environments. Another limitation of aluminum is its relatively
low strength at elevated temperatures.
Two alloys of aluminum are commonly used in refinery
applications. Alloy 3003, alloyed with manganese, has been
successfully used in tower overhead condensers cooled by water on
the condenser tubeside. Resistance to shell-side aqueous sulfide
corrosion has been good, but waterside pitting and fouling has
detracted from the use of aluminum tubes. Aluminum alloy 3003
can be successfully used in sour water overhead condensers if the
process fluid velocity is kept low to avoid erosion-corrosion. Alloy
6061-T6 is a magnesium and silicon aluminum alloy that is
precipitation hardenable. It has been used for pressure-containing
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Materials of Construction for Refinery Applications
components, such as exchanger shells, because of its relatively high
strength.
Aluminum and its alloys have been used for distillation tower tray
components subject to naphthenic acid corrosion. They have also
been applied in various forms to protect furnace tubes and piping in
high-temperature hydrogen sulfide/hydrogen services.
15.6.9.4 Titanium and Its Alloys
Titanium is a highly reactive metal, which depends on a protective
oxide film for corrosion protection. Titanium is not suitable for
high-temperature service and because of its reactivity, must be
welded and cut under inert gas conditions to prevent contamination
and embrittlement. From a practical standpoint, use of titanium in
refinery service is limited to temperatures below 500F (260C).
With hydrogen present, temperatures should not exceed 350F
(177C) to prevent embrittlement by hydride formation.
Titanium exhibits high corrosion resistance to most refinery
streams. Tubes made from pure titanium (grade 2) are used
extensively in overhead coolers and condensers on a number of
units to prevent corrosion by chlorides, sulfides, and aqueous sulfur
dioxide. These tubes can corrode, however, under acidic deposits.
Titanium tubes are very useful at locations where seawater or
brackish water is used for cooling. They are also good in sour water
stripper overhead service.
Titanium alloyed with nickel and molybdenum (grade 12) is
generally better than grade 2 and can be used in underdeposit
corrosion and higher temperature services where the pure grade is
unsuitable. Anodizing and high-temperature air oxidation of pure
titanium can also improve the corrosion performance of titanium.
15.6.10 Non-Metallic Materials
15.6.10.1 Refractories
Refractories are inorganic ceramic materials that are normally used
either for thermal insulation, corrosion resistance, erosion
resistance, or any combination of these. Refractories are available in
several product forms, including ceramic fiber blankets, bricks,
castable mixes (similar to concrete), and plastic-ramming mixes.
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Refractories generally have very high-temperature resistance
(3000F [1649C]), are chemically inert to most chemicals and
solvents and, when in cast form, have very good erosion resistance.
Typical refinery uses for refractories are as thermal insulation on the
inside of fired heaters and boilers, for insulation and erosion
resistance in catalyst handling systems, such as in fluid catalytic
cracking units, and as corrosion-resistant lining in sulfuric acid
production and sulfur recovery units.
15.6.10.2 Plastics
An engineering plastic may be defined as a synthetic organic
polymer resin capable of being formed into load-bearing shapes that
enable it to be used in the same manner as metallic materials.
Plastics are manmade materials, and each type of plastic was
originally developed with a specific application in mind. For this
reason, a large number of plastic materials exist, which are available
for use in equipment design, and new plastics are being developed
on a regular basis. Each particular polymer has its own unique
properties. This vast diversity in material types and properties is one
of the major differences between metals and plastics. Plastics are
divided into two groups:
1. Thermoplastic materials
2. Thermosetting materials.
Thermoplastics are capable of being repeatedly softened by an
increase in temperature and hardened by a decrease in temperature.
Thermosets, on the other hand, undergo a cure in the molding or
forming process and, as a result of chemical reactions (produced by
heat and/or added chemical catalysts), become substantially
infusible.
Plastics generally exhibit excellent corrosion resistance in the type
of environments for which they were originally developed.
However, like metals, plastics do suffer from corrosion when
exposed to some environments. Corrosion mechanisms in plastics
are generally completely different than those that occur in metallic
components. Corrosion in plastics is best defined as any reaction
with an environment that significantly changes the physical and
chemical properties of the plastic. The term corrosion rate is not
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normally applicable to plastics. Typical corrosion mechanisms
found in plastics include polymer chain scission (cutting), liquid
oxidation degradation, melting, swelling, chemical embrittlement,
and stress cracking, just to name a few. There are as many different
failure modes for plastics as there are types of plastic materials.
In recent years, some thermoplastics have found their way into a
limited number of refinery applications. Some of the more common
materials include:
•
Polyvinyl chloride (PVC)—PVC is the most widely used thermoplastic in the manufacture of plastic pipe, fittings, and valves
because of its economy, versatility, excellent chemical resistance, high tensile strength, good impact resistance, and its ability to withstand long-term exposure to pressure.
•
Chlorinated polyvinyl chloride (CPVC)—CPVC has all of the
properties of PVC plus the ability to handle temperatures up to
210F (99C). This makes CPVC pipe, fittings, and valves suitable not only for hot corrosive service, but also for hot water distribution systems.
•
Polyethylene (PE)—PE is the lightest thermoplastic and is
widely used due to its low cost, good chemical resistance, and
temperature resistance up to 140F (60C). There are two commercial forms of PE—high density (HDPE) and low density
(LDPE). Each has its own specific strengths and weaknesses.
•
Polypropylene (PP)—PP is another widely used thermoplastic.
PP is suitable for corrosive waste as well as pressure applications
because of its inertness to a wide range of chemicals, including
most solvents and because of its ability to withstand temperatures up to 200F (93C).
•
Polyvinylidene fluoride (PVDF)—PVDF features remarkable
high-temperature performance. PVDF pipe and fittings can handle corrosive fluids at working temperatures up to 280F
(138C). Other PVDF qualities are excellent chemical resistance
to halogens and resistance to weathering (UV-resistant). PVDF
is also highly resistant to Gamma radiation.
•
Polytetrafluoroethylene (PTFE)—PTFE is literally the superman
of thermoplastic materials, with excellent corrosion resistance to
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most chemicals and solvents and the ability to withstand longterm exposure at temperatures up to 450F (232C).
Thermoplastic materials are available in a number of product forms,
piping, valves, fittings, sheets, etc. Thermoplastics are available
either alone or as a corrosion-resistant lining on carbon steel
components.
15.6.10.3 Thermosetting Resins
Thermosetting resins, such as polyesters, epoxies, urethanes, and
vinyl esters, have excellent chemical resistance and are normally
used either as a spray-on type coating (paint) or in combination with
some type of inorganic reinforcing material, such as glass or carbon
fibers. The most common form of this material used in refineries is
fiberglass, which is a thermosetting plastic resin reinforced with
glass or carbon fibers. The properties of a fiberglass material are
determined by the type of resin used to produce the material and the
type of material used for reinforcement. Typical resins used for
refinery applications are polyester, epoxy, and vinyl ester. Fiberglass
materials are commonly used for chemical storage tanks and drums.
Fiberglass is also commonly used in refineries as a lining material to
protect the internal surface of storage tank bottoms from corrosion.
15.7 Heat Treatment
Heat treatment is defined by the American Society for Testing and
Materials (ASTM), the Society of Automotive Engineers (SAE),
and the American Society for Metals (ASM) as:
An operation, or combination of operations, involving the heating
and cooling of a metal or alloy in the solid state for the purpose of
obtaining certain desirable conditions or properties.
15.7.1 Normalization
Normalizing consists of heating steel to a temperature 50F to
100F (10C to 37.8C) above its specific upper transformation
temperature. The steel is then cooled in still air to a temperature that
is well below the transformation range. Normalizing is usually used
as a conditioning treatment, notably for refining the grains of steels
that have been subjected to high temperatures for forging or other
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hot-working operations. Normalizing is normally followed by
another heat-treating operation, such as tempering or hardening.
15.7.2 Annealing
Annealing may be described as heating a metal above a critical
temperature range, holding for a certain period of time, and slowly
cooling. The process of annealing consists of three stages:
•
Recovery
•
Recrystallization
•
Grain growth.
The annealing temperature will vary with the composition of the
metal involved. For instance, the annealing temperature for lowcarbon steels will vary with carbon content from 1600F to 1700F
(871C to 927C), while that for high-carbon steels will vary from
1450F to 1500F (788C to 816C). The time required to
homogenize metals will vary with the specific metal from hours to
several days. Cooling is always slow to ensure a homogeneous
structure and obtain maximum softness.
A ferrous metal may be annealed to improve machinability,
facilitate cold work, improve mechanical properties, or increase
dimensional stability. When it is desired to preserve most of the
mechanical properties imparted by cold work, but at the same time
(to an extent) maintain corrosion resistance, a stress-relief heat
treatment may be more suitable than annealing.
Nonferrous alloys are usually heated to temperatures just below the
solidus temperature (just below melting) for annealing. For
nonferrous materials, annealing is performed to remove the effects
of cold work, cause coalescence of precipitates from solid solution
or both.
15.7.3 Quenching
Quenching is the rapid cooling of a steel or alloy from the
austenitizing temperature by immersing the work piece in a liquid or
gaseous medium. The quenching medium may be water, brine,
caustic, oil, polymer, air, or nitrogen. Quenching is used to obtain
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maximum possible hardness and strength from a steel. Either
tempering or stress relieving almost always follows quenching.
15.7.4 Stress Relieving
Stress relieving, like tempering, is always accomplished by heating
the work piece to a temperature below the lower transformation
temperature for steels and alloys. Stress relieving is primarily
performed to relieve stresses that have been imparted to the work
piece from processes, such as forming, rolling, machining, or
welding. The usual procedure is to heat the work piece to a preestablished temperature long enough to reduce residual stresses to
an acceptable level. This is a time and temperature dependent
operation, which is normally followed by cooling at a relatively
slow rate to avoid the creation of new stresses.
The amount of residual stress in a material plays a critical role in
determining its susceptibility to many forms of stress corrosion
cracking. Therefore, stress relieving can be specified to improve a
material’s resistance to this corrosion mechanism. Carbon steel
weldments are often stress relieved for this reason. (Another reason
is to maintain dimensional stability.)
Stress relieving can be used to reduce material costs for equipment
in caustic service by preventing stress corrosion cracking. The
concentration and temperature of a sodium hydroxide solution
(caustic soda) determine whether or not carbon steel will suffer
stress corrosion cracking. When there is an indication that cracking
will occur, specification of a stress-relief heat treatment would
permit the use of carbon steel that would not crack.
15.7.4.1 Solution Heat Treatment
It is sometimes necessary to put certain precipitates back into a solid
solution to improve corrosion resistance. For instance, unstabilized
austenitic stainless steels, when sensitized either in-service or by
welding, may have their corrosion resistance restored if this heat
treatment is specified. Solution heat treatment involves heating at
1650F to 2000F (899C to 1093C) for one hour per inch (25mm)
of maximum thickness (one hour minimum) and quenching in water
to black heat within three minutes. The actual temperature required
for solution heat treatment depends on the type of stainless steel.
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Solution heat treatment places the chromium carbides back into
solution.
When either stress relieving or annealing of austenitic stainless steel
is thought to be required, the designer should specify only solution
heat treatment. If the equipment involved has a geometry that will
not allow it to take the water quench required by this heat treatment
process without warping, the designer has two options. He can:
1. Consult a metallurgist to determine whether the heat treat
ment is really necessary.
2. Change to a material that does not require a heat treatment to
preserve corrosion resistance.
15.7.5 Specialized Heat Treatments
Several specialized heat treatments are applied to refinery
equipment either to enhance corrosion resistance in certain
environments, facilitate in-service repair, or restore mechanical
properties that have deteriorated during long-term service. Some of
these treatments include:
•
De-embrittlement—Heat treatment is applied prior to weld
repair of C-1/2 Mo and other Cr-Mo alloy steels, such as 1-1/4
Cr-1/2 Mo, after long-term exposure in high-temperature service. De-embrittlement restores ductility to the material so that
welding repairs can be successfully made free of cracking. The
treatment involves heating the weld zone to 1300F (704C),
holding for 4 hours to 8 hours, and cooling at 400F (204C) per
hour per inch of thickness.
•
Dehydrogenation—Heat treatment is normally applied to steels
prior to repair welding of refinery equipment exposed to services
that can cause hydrogen-induced cracking. These services
include wet hydrogen sulfide service, high-pressure/high-temperature hydrogen service, caustic service, or amine service. The
typical procedure is to bake out any residual atomic hydrogen in
the steel by heating it to 400F to 600F (204C to 315C) and
holding for 2 hours to 4 hours, depending on the thickness of the
material and the severity of the exposure. The procedure is
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intended to help avoid delayed hydrogen cracking during or after
repair welding.
•
Stabilization heat treatment—Chemically stabilized grades of
stainless steel (type 321 and type 347) may become sensitized
after prolonged exposure in the sensitization temperature range
(700F to 1500F [371C to 816C]). Sensitization is the term
used to describe the phenomenon of intergranular carbide precipitation that occurs in austenitic steels when subjected to temperatures in the sensitization temperature range. The resistance
of these stainless steels to polythionic acid stress corrosion
cracking may be significantly improved by a stabilization heat
treatment performed prior to placing the equipment in service.
Typically, stabilization heat treatments consist of heating the
material to 1650F (899C) and holding at that temperature for 2
hours to 4 hours. The material is then cooled to ambient temperature. The rate of cooling is controlled to minimize distortion.
15.7.6 What the Designer Should Know About
Heat Treatments
The designer should be familiar with the various heat treatments
available for a particular metal or alloy. It is best to consult with a
metallurgist to determine the actual need for heat treatment and, if
required, what the schedule should be. The designer should specify
the full heat treatment schedule required. A notation of anneal,
stress relieve, or solution heat treatment, etc., is not adequate. The
following is an example of a heat treatment schedule specified for a
large waste storage tank, 60 feet (18m) in diameter and 35 feet
(11m) high, to obviate stress corrosion cracking and, at the same
time, to avoid warping the large tank.
1. Heat to 600F (315C).
2. Above 600F (315C), heating is not to exceed 100F
(37.8C) per hour. During this period, the temperature gradient is not to exceed 125F (52C) in any 15-ft (5-m) interval
and then there should not be a greater variation than 200F
(93C) between the lowest and highest temperature points in
the vessel.
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3. The temperature is to be held at a minimum of 1100F
(593C) for a period of at least one hour.
4. The rate of cooling should not be greater than 125F (52C)
per hour. During this period, the greatest variation between
the highest and the lowest temperature in the vessel is not to
exceed 200F (93C).
5. Below 600F (315C), no restriction on the cooling rate is
required.
The heat treatment schedule is not usually as detailed as the
schedule described above. For instance, a schedule for stress
relieving a piece of production equipment not susceptible to
warping may read, "Heat slowly to a temperature of 1100F to
1200F (593C to 648C) and hold for one hour per inch of
thickness, then furnace cool to ambient temperature."
No matter which alloy is used, the complete heat treatment should
be clearly defined in the designer's specification. However, some
engineers argue that such a treatment is up to the heat treater's
discretion and all the designer needs to do is to specify the end
result, such as the desired hardness of the part or equipment.
Consulting with the heat treater is a prudent step, but the designer
should specify the agreed upon heat treatment schedule.
For example, tool steel blocks that were to be used as important
parts in a piece of equipment were sent to a heat treater with the
specification that the blocks "are to be heat treated to a Rockwell C
hardness of 63." After the parts were quenched from the hardening
temperature, the heat treater found that the parts were already at the
required hardness so he did not bother to temper the parts (like he
should have) because of fear that the parts would become too soft.
Consequently, the blocks were so brittle that they failed
immediately when used. No recourse was expected from the heat
treater because tempering had not been specified. The designer
should always specify the complete heat treatment schedule,
including temperature, time at heat, quenching medium, quench
temperature, and the tempering temperature (when a temper is
required). Such a specification can also be used later by the
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inspector to assure that the required heat treatment has been
accomplished.
15.7.7 Heat Treatment Verification
Because the heat treatment of metals and alloys often affects
corrosion resistance, it is essential that the designer impose some
manner of quality control on heat treatment operations. The
importance of assuring that the proper austenitizing temperature, the
type of quenching media, the tempering temperature, and the time at
heat are maintained cannot be overemphasized. It is also essential to
assure that the heat-treating equipment is in good operating
condition. For instance, standard temperature thermocouples can be
used to determine if a furnace is actually operating at the set
temperature. This procedure has detected furnaces operating at
temperatures hundreds of degrees off the designated set
temperature. Competent heat treaters routinely check their furnace
temperatures and, therefore, their records may be used by inspectors
as verification.
On critical jobs, the designer can specify that specimens of the same
material are heat treated along with the actual process equipment or
part. After heat treatment, the specimen may be sectioned, polished,
etched, and observed under a microscope to verify that the required
microstructure has been obtained. When appropriate, the hardness
of the process equipment or part may be determined and compared
with the specified hardness.
15.7.8 Heat Treatment for Welds
15.7.8.1 Preheat
Preheat involves heating the weldment to a prescribed temperature
above ambient temperature prior to welding and maintaining this
minimum temperature for the duration of welding. Preheating may
be conducted to reduce residual stress, reduce distortion, lower heataffected zone hardness, and prevent under-bead cracking. Typical
preheat treatment temperatures for the refinery steels are included in
Table 15.9 .
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Table 15.9: Preheat Temperatures for Refinery Steels
Steel
Carbon
Carbon-1/2 Mo
1-1/4 Cr-1/2 Mo
2-1/4 Cr-1 Mo
5 Cr-1/2 Mo
7 Cr-1 Mo
9 Cr-1 Mo
12 Cr
17 Cr
300 series stainless
Nickel alloy steels
Preheat Temperature
50F (10C)
50F (10C)
300F (149C)
350F (177C)
350F (177C)
350F (177C)
350F (177C)
300F (149C)
50F (10C)
50F (10C)
200F (93C)
Preheat requirements are usually specified by the code or standard
under which the equipment is built. Some are mandatory
requirements and others are recommended.
15.7.8.2 Postweld Heat Treatment
Postweld heat treatment conditions the weldment following
welding. Its application, or misapplication, can dramatically affect
in-service mechanical and corrosion performance. PWHT is
conducted at an elevated temperature, slightly below the
transformation temperature for the alloy involved. The PWHT
temperature is high enough for stress to flow and hard
microstructures to temper. This results in reduced residual stress and
a softer weld and heat-affected zone (HAZ).
In general, PWHT improves corrosion resistance, reduces the
chances of stress corrosion cracking, increases ductility, and
improves toughness of the material, especially in the heat-affected
zones next to the weld. Table 15.10 contains typical temperature
ranges commonly used for postweld heat treatment of refinery steels
and, where appropriate, the hardness limit acceptable.
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Table 15.10: PWHT Temperatures for Refinery Steels
Steel
Carbon
Carbon-1/2 Mo
1-1/4 Cr-1/2 Mo
2-1/4 Cr-1 Mo
5 Cr-1 Mo
7 Cr-1 Mo
9 Cr-1 Mo
12 Cr
17 Cr
300 series stainless
Duplex stainless steels
Nickel alloy steels
PWHT Temperature
Range
1100F-1200F (593C648C)
1100F-1325F (593C718C)
1300F-1375F (704C746C)
1300F -1400F (704C760C)
1300F -1400F (704C760C)
1300F -1400F (704C760C)
1300F -1400F (704C760C)
1350F -1450F (732C788C)
None
None
Hardness, BHN
 200
 225
 225
 241
 241
 241
 241
 241
100F -1175F (37.8C635C)
The holding time at temperature is typically one hour per inch of
weld thickness. As with preheat, PWHT requirements are found in
the code or standard to which the equipment is fabricated. Many
times PWHT is specified solely for the purpose of preventing stress
corrosion cracking even if it is not specified by the fabrication code
being utilized. Amine and/or caustic service are typical refinery
processes where PWHT is specified to prevent stress corrosion
cracking.
Austenitic stainless steels, such as type 304 and type 316, remain
austenitic throughout the welding process and do not harden. They
are generally not preheated or postweld heat-treated, and the
interpass temperature for the 300 series alloys is often restricted to
300F (149C) to preserve corrosion resistance. When residual
stress is judged unacceptable, significant stress reduction can be
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accomplished by heating in the range of 1550F to 1650F (843C
to 899C) for 15 minutes to 60 minutes and cooling rapidly to room
temperature.
Since welding also results in the sensitization of the regular grades
(types 304, 316, 317), the use of low-carbon (types 304L, 316L,
317L) or chemically stabilized grades (types 321, 347) are very
often used to minimize sensitization in welded fabrications. If
sensitization has occurred, the regular grades can be solutionannealed by heating to about 2000F (1093C), followed by water
quenching. Although this will re-dissolve the precipitated chromium
carbides, accomplishing the process on welded assemblies in the
field may not be practical.
15.7.9 Normalizing
Postweld heat treatment of refinery steels tempers the welds and
reduces residual stresses. The weld metal, however, retains a
microstructure considerably different than the adjacent base metal.
In most services this difference is of no consequence. In some
situations, however, such as acidic aqueous environments,
preferential weld corrosion can occur. This selective attack of the
weld can often be reduced by normalizing the weldment in the
temperature range of 1500F to 1600F (816C to 871C) and then
air-cooling. Elevated temperature treatment results in a weld
microstructure having corrosion behavior nearly identical to the
base metal. Since normalization is done at a relatively high
temperature, distortion of the welded assembly can easily result.
Special fixturing and handling may be needed to prevent distortion.
15.8 Welding
15.8.1 The Nature of Welding
Welding is the process of joining materials by fusion. Most refinery
equipment is fabricated by welding, and most metals used in the
refinery can be joined by one or more of the many welding
processes available. In addition to new construction, welding is
extensively used to repair, modify, and line refinery equipment
during shutdowns. Safe operation of pressure-containing equipment
depends on welded joints of acceptable quality that meet or exceed
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the requirements and procedures of applicable codes and standards.
Welds must be clean and free from defects, including porosity, slag,
inclusions, cracks, incomplete penetration, and lack of fusion.
Welding alters the base material and the changes that occur can
result in degraded mechanical, metallurgical, and corrosion
performance in and near the weld.
Failure mechanisms associated with welding include:
•
Fatigue cracking
•
Stress corrosion cracking
•
Hydrogen embrittlement
•
Sulfide stress cracking
•
Accelerated corrosion
•
Preferential weld zone corrosion.
The following information will briefly examine some of the
principal welding processes used on refinery equipment, welding
procedures, and various heat treatments used to enhance the
properties and performance of weldments.
Welding is used almost universally in the fabrication of process
equipment. Over 90% of all permanent closures are made by fusion
welding or brazing. For all its utility, welding has inherent
characteristics that can foster corrosion, such as:
1. The cast structure of a weld can be quite different from the usual
wrought structure of the parent material.
2. Weld spatter can create obstructions that can result in localized
corrosion.
3. Many weld joints can contain crevices if not welded properly.
4. The weld surface is generally rougher than the parent material's
surface.
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5. Shielded metal arc and submerged arc welding processes
generate slag, which can establish corrosion cells.
6. Welding entails intense localized heat, which creates heataffected zones in the parent metal where phase transformations
and precipitation may occur.
7. Welds contain internal shrinkage stresses.
8. Residue not removed from welding and brazing fluxes may be
corrosive.
Although welding has some drawbacks, it is still the best and most
sound method of closure available. Rivets and bolting, for instance,
have built-in crevices and are difficult to maintain.
15.8.2 Welding Decisions
Due to the problems associated with welding, the designer must
properly design and specify the welds in his structures.
Unfortunately, simply noting on the drawing that the structure is to
be welded is standard procedure with some designers. Such a
specification leaves the welding decisions up to the welder or the
welding foreman who probably does not know the process
conditions involved. The end use of the equipment must be carefully
considered in advance, and the appropriate weld design must be
specified while the equipment is still in the design stage, not when it
is in the weld shop.
15.8.3 Welding Processes
Various welding processes a designer can specify include:
•
Shielded Metal Arc Welding (SMAW), commonly called stick
electrode welding.
•
Gas Metal Arc Welding (GMAW), commonly called MIG welding. This process can be manual, semi-automatic, or automatic.
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•
Gas Tungsten Arc Welding (GTAW), common called TIG or
heliarc welding.
•
Submerged Arc Welding (SAW), commonly called subarc welding. This process can be semi-automatic or automatic.
•
Gas Welding. Oxyacetylene is the most common gas welding,
although there are other gas combinations.
•
Brazing.
Each process has its individual characteristics. Therefore, it is
important that the designer carefully select the welding so he
preserves the material's corrosion resistance. For instance, although
the SMAW process is inherently no less corrosion resistant than the
inert gas process, the SMAW process may result in slag inclusions
from sloppy welding techniques, while the inert gas process does
not produce any slag inclusions.
The adverse effect of slag inclusions was pointedly observed in a
shielded metal arc welded stainless steel tank containing an acid.
When the tank was emptied, cleaned out, and given a routine
inspection, it was noted that the double-butt welded girth weld
inside bead had been aggressively attacked, while the adjacent tank
wall was relatively unaffected. The failure was blamed on very poor
workmanship because the slag had not been adequately removed.
The remainder of the inside weld was gouged out and rewelded with
the inert gas process. After that, no more corrosion problems were
reported.
When the fabricator is equally familiar with both metal arc welding
and inert gas welding, when practical, inert gas welding should be
specified by the designer for corrosive service. Brazing, silver
soldering, and soldering should not be specified for corrosive
conditions. Exceptions to this rule may exist; however, these joining
processes usually involve a different material than the parent metal,
which can lead to galvanic corrosion.
15.8.3.1 Shielded Metal Arc Welding (SMAW)
Shielded metal arc welding (SMAW) is the most commonly used
and most versatile welding process applicable to shop and field
work on refinery equipment. SMAW uses an electrode consisting of
a straight piece of filler metal coated with a flux covering. The flux
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melts with the wire and provides a gaseous shield to protect the
molten weld puddle from oxidation. The flux also acts as a
deoxidizing agent to improve cleanliness in the weld deposit.
The process requires a relatively high degree of welder skill, but can
be successfully used in all positions and under a wide variety of
welding parameters. Hydrogen pickup during welding can cause
porosity and cracking problems. A common source of hydrogen is
moisture in the electrode coating. To control hydrogen problems,
low-hydrogen electrodes may be used. The bulk of carbon steel
welding performed in the refinery uses low-hydrogen electrodes,
with E7018 being the most common.
15.8.3.2 Gas Metal Arc Welding (GMAW)
Gas metal arc welding (GMAW) uses a filler metal wire fed
continuously through a gun or torch. A gas or mixture of gases that
passes through the torch provides shielding. A trigger on the gun
starts or stops wire movement along with gas flow. Wire speed is
controlled at the feeder, which holds the filler wire coil. Normally,
only a small amount of glassy slag is produced, and the absence of
flux decreases the amount of hydrogen in the weldment.
Compared to SMAW, GMAW permits higher rates of weld metal
deposition with fewer stops and starts, does not require slag
removal, and avoids the possibility of slag entrapment in the weld.
A relatively low degree of welding skill is required for GMAW, but
care must be taken to assure that sidewall fusion takes place
between the weld and base metal.
In GMAW, electrical parameters can be varied to provide several
different modes of metal transfer across the arc from the
consumable wire electrode. Modes of transfer include:
•
Spray transfer—High current, high deposition rate.
•
Short circuiting arc—The short-arc, low-heat input process is
ideal for welding light-gauge tubing and sheet metal.
•
Globular transfer—A relatively low current to filler metal diameter is used that produces transfer by droplets.
•
Pulsed arc—Similar to spray transfer except the electrical waveform is cycled to produce short spurts of metal spray with a
lower total heat input.
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15.8.3.3 Gas Tungsten Arc Welding (GTAW)
Gas tungsten arc welding (GTAW) uses a non-consumable electrode
(most commonly tungsten), an inert gas shield delivered through the
gun, and filler metal that is manually fed into the weld. Welds,
termed autogenous welds, can also be made without the introduction
of filler metal. The heat of the electric arc and molten puddle melts
the filler. GTAW produces welds of high quality with low hydrogen
content, but at relatively slow welding rates. It requires a relatively
high degree of welder skill and is commonly used to make root
passes in low- and high-alloy steel welds.
15.8.3.4 Submerged Arc Welding (SAW)
Submerged arc welding (SAW) is similar to GMAW except the
protective gas shield is replaced by granular flux, which is similar to
the flux on coated electrodes. There are two primary flux types:
•
Neutral flux
•
Active flux.
The neutral fluxes do not add metallic elements to the weld deposit
and are preferred over active fluxes because the deposit chemistry is
more easily controlled. With active fluxes, variations in heat input
during welding can alter the chemistry of weld deposits. SAW is
usually performed in the flat position (welding torch pointing
down). With a special setup, welds can also be made with the torch
in the horizontal position. SAW is normally used during shop
fabrication of refinery equipment and offers the advantages of high
deposition rates combined with good weld quality.
15.8.4 Welding Procedures and Welder Qualification
Most codes and standards under which petroleum refinery
equipment is fabricated and maintained require that welding
conform to Section IX of the ASME Boiler and Pressure Vessel
Code. Section IX requires that procedures used for welding be
tested prior to use to insure that they are capable of producing joints
having adequate mechanical properties. The details of the welding
procedure are first written as a Welding Procedure Specification
(WPS). The WPS is then used to weld test pieces. Destructive tests,
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such as tensile tests, bend tests and, when required, impact
toughness tests, are performed on the test pieces to evaluate the
mechanical properties of the weld.
The actual parameters, which are used to weld the test samples, are
recorded in the Procedure Qualification Record (PQR) along with
the results of the mechanical test(s). A welder who performs the
welding on the procedure qualification samples is automatically
qualified to use the qualified procedure for production welding.
Other welders who wish to use the qualified procedure must
produce performance test welds of acceptable quality and be
evaluated using either destructive tests or radiographic examination.
This performance qualification test is to insure that the welder can
produce a weld without defects using the qualified procedure. The
record of the welder's performance qualification test result is the
Welder Performance Qualification (WPQ).
Welders and procedures must be requalified if any of the essential
variables in the welding process are changed. Essential variables are
described in the applicable code or standard for each welding
process. For example, a change in base metal or a change in filler
metal can require requalification. Other essential variables pertain to
the:
•
Type of joint
•
Electrical characteristics
•
Welding technique
•
Preheat treatment
•
Postweld heat treatment
•
Shielding gas.
Codes and standards differ in identifying essential variables.
15.8.5 Inspection of Welding Electrodes and
Filler Metal
Many corrosion failures have been caused by the mix-up of
electrodes or filler rods in the fabricators' bins. The manufacturer of
welding electrodes and filler rods is required to make many tests
prescribed by the American Welding Society (AWS) on his product
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before it is sealed into cartons. Consequently, the integrity of the
welding electrodes can only be relied upon prior to opening the
cartons. For this reason, the designer should not only specify the
types of electrodes required, but also stress that the company's
inspector allow only unopened cartons of the electrodes to be used
on the job. Those electrodes must then be kept isolated from other
welding jobs and carefully marked to avoid mix-ups.
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References
1.A27/A27M-95, “Standard Specification for Steel Castings,
Carbon, for General Application” (West Conshohocken, PA:
ASTM, 1995).
2. A53/A53M-99, “Standard Specification for Pipe, Steel, Black
and Hot-Dipped, Zinc-Coated, Welded and Seamless” (West
Conshohocken, PA: ASTM, 1999).
3. A105/A105M-98, “Standard Specification for Carbon Steel
Forgings for Piping Applications” (West Conshohocken, PA:
ASTM, 1998).
4. A106-99, “Standard Specification for Seamless Carbon Steel
Pipe for High-Temperature Service” (West Conshohocken,
PA: ASTM, 1999).
5. A134-96, “Standard Specification for Pipe, Steel, ElectricFusion (Arc)-Welded (Sizes NPS16 and Over)” (West Conshohocken, PA: ASTM, 1996).
6. A135-97c, “Standard Specification for Electric-ResistanceWelded Steel Pipe” (West Conshohocken, PA: ASTM, 1997).
7. A139-96e1, “Standard Specification for Electric-Fusion
(Arc)-Welded Steel Pipe (NPS4 and Over)” (West Conshohocken, PA: ASTM, 1996).
8. A167-96, “Standard Specification for Stainless and HeatResisting Chromium-Nickel Steel Plate, Sheet, and Strip”
(West Conshohocken, PA: ASTM, 1996).
9. A176-97, “Standard Specification for Stainless and HeatResisting Chromium Steel Plate, Sheet, and Strip” (West
Conshohocken, PA: ASTM, 1997).
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10. A178/A178M-95, “Standard Specification for ElectricResistance-Welded Carbon Steel and Carbon-Manganese
Steel Boiler and Superheater Tubes” (West Conshohocken,
PA: ASTM, 1995).
11. A179/A179M-90a(96)e1, “Standard Specification for Seamless Cold-Drawn Low-Carbon Steel Heat Exchanger and
Condenser Tubes” (West Conshohocken, PA: ASTM, 1996).
12. A181/A181M-95b, “Standard Specification for Carbon
Steel Forgings, for General Purpose Piping” (West Conshohocken, PA: ASTM, 1995).
13. A182/A182M-98a, “Standard Specification for Forged or
Rolled Alloy-Steel Pipe Flanges, Forged Fittings, and Valves
and Parts for High-Temperature Service” (West Conshohocken, PA: ASTM, 1998).
14. A192/A192M-91(96)e1, “Standard Specification for Seamless Carbon Steel Boiler Tubes for High-Pressure Service”
(West Conshohocken, PA: ASTM, 1996).
15. A193/A193M-99, “Standard Specification for Alloy-Steel
and Stainless Steel Bolting Materials for High-Temperature
Service” (West Conshohocken, PA: ASTM, 1999).
16. A194/A194M-98b, “Standard Specification for Carbon and
Alloy Steel Nuts for Bolts for High-Pressure or High-Temperature Service, or Both” (West Conshohocken, PA: ASTM,
1998).
17. A204/A204M-93(1998), “Standard Specification for Pressure Vessel Plates, Alloy Steel, Molybdenum” (West Conshohocken, PA: ASTM, 1998).
18. A209/A209M-98, “Standard Specification for Seamless
Carbon-Molybdenum Alloy-Steel Boiler and Superheater
Tubes” (West Conshohocken, PA: ASTM, 1998).
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19. A210/A210M-96, “Standard Specification for Seamless
Medium-Carbon Steel Boiler and Superheater Tubes” (West
Conshohocken, PA: ASTM, 1996).
20. A213/A213M-99a, “Standard Specification for Seamless
Ferritic and Austenitic Alloy-Steel Boiler, Superheater, and
Heat-Exchanger Tubes” (West Conshohocken, PA: ASTM,
1999).
21. A214/A214M-96, “Standard Specification for ElectricResistance-Welded Carbon Steel Heat-Exchanger and Condenser Tubes” (West Conshohocken, PA: ASTM, 1996).
22. A216/A216M-93 (1998), “Standard Specification for Steel
Castings, Carbon, Suitable for Fusion Welding, for HighTemperature Service” (West Conshohocken, PA: ASTM,
1998).
23. A217/A217M-98, “Standard Specification for Steel Castings, Martensitic Stainless and Alloy, for Pressure-Containing
Parts, Suitable for High-Temperature Service” (West Conshohocken, PA: ASTM, 1998).
24. A226/A226M-95, “Standard Specification for ElectricResistance-Welded Carbon Steel Boiler and Superheater
Tubes for High-Pressure Service” (West Conshohocken, PA:
ASTM, 1995).
25. A234/A234M-99, “Standard Specification for Pipe Fittings
of Wrought Carbon Steel and Alloy Steel for Moderate and
High-Temperature Service” (West Conshohocken, PA:
ASTM, 1999).
26. A240/A240M-99, “Standard Specification for Heat-Resisting Chromium and Chromium-Nickel Stainless Steel Plates,
Sheet, and Strip for Pressure Vessels” (West Conshohocken,
PA: ASTM, 1999).
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27. A249/A249M-98e1, “Standard Specification for Welded
Austenitic Steel Boiler, Superheater, Heat-Exchanger, and
Condenser Tubes” (West Conshohocken, PA: ASTM, 1998).
28. A250/A250M-95, “Standard Specification for ElectricResistance-Welded Ferritic Alloy-Steel Boiler and Superheater Tubes” (West Conshohocken, PA: ASTM, 1995).
29. A268/A268M-96, “Standard Specification for Seamless and
Welded Ferritic and Martensitic Stainless Steel Tubing for
General Service” (West Conshohocken, PA: ASTM, 1996).
30. A269-98, “Standard Specification for Seamless and Welded
Austenitic Stainless Steel Tubing for General Service” (West
Conshohocken, PA: ASTM, 1998).
31. A283/A283M-98, “Standard Specification for Low and
Intermediate Tensile Strength Carbon Steel Plates” (West
Conshohocken, PA: ASTM, 1998).
32. A285/A285M-90, “Standard Specification for Pressure Vessel Plates, Carbon Steel, Low and Intermediate-Tensile
Strength” (West Conshohocken, PA: ASTM, 1990).
33. A297/A297M-97 (1998), “Standard Specification for Steel
Castings, Iron-Chromium and Iron-Chromium-Nickel, Heat
Resistant, for General Application” (West Conshohocken,
PA: ASTM, 1998).
34. A299/A299M-97, “Standard Specification for Pressure Vessel Plates, Carbon Steel, Manganese-Silicon” (West Conshohocken, PA: ASTM, 1997).
35. A302/A302M-97, “Standard Specification for Pressure Vessel Plates, Alloy Steel, Manganese-Molybdenum and Manganese-Molybdenum-Nickel” (West Conshohocken, PA:
ASTM, 1997).
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36. A312/A312M-99, “Standard Specification for Seamless and
Welded Austenitic Stainless Steel Pipes” (West Conshohocken, PA: ASTM, 1999).
37. A320/A320M-98, “Standard Specification for Alloy Steel
Bolting Materials for Low-Temperature Service” (West Conshohocken, PA: ASTM, 1998).
38. A333/A333M-99, “Standard Specification for Seamless and
Welded Steel Pipe for Low-Temperature Service” (West Conshohocken, PA: ASTM, 1999).
39. A334/A334M-99, “Standard Specification for Seamless and
Welded Carbon and Alloy-Steel Tubes for Low-Temperature
Service” (West Conshohocken, PA: ASTM, 1999).
40. A335/A335M-99, “Standard Specification for Seamless
Ferritic Alloy-Steel Pipe for High-Temperature Service”
(West Conshohocken, PA: ASTM, 1999).
41. A336/A336M-99, “Standard Specification for Alloy Steel
Forgings for Pressure and High-Temperature Parts” (West
Conshohocken, PA: ASTM, 1999).
42. A350/A350M-99, “Standard Specification for Carbon and
Low-Alloy Steel Forgings, Requiring Notch Toughness Testing for Pipe Components” (West Conshohocken, PA: ASTM,
1999).
43. A351/A351M-94ae1, “Standard Specification for Castings,
Austenitic, Austenitic-Ferritic (Duplex), for Pressure-Containing Parts” (West Conshohocken, PA: ASTM, 1994).
44. A352/A352M-93 (1998), “Standard Specification for Steel
Castings, Ferritic and Martensitic, for Pressure-Containing
Parts, Suitable for Low-Temperature Service” (West Conshohocken, PA: ASTM, 1998).
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45. A354-98, “Standard Specification for Quenched and Tempered Alloy Steel Bolts, Studs, and Other Externally
Threaded Fasteners” (West Conshohocken, PA: ASTM,
1998).
46. A358/A358M-98, “Standard Specification for ElectricFusion-Welded Austenitic Chromium-Nickel Alloy Steel
Pipe for High-Temperature Service” (West Conshohocken,
PA: ASTM, 1998).
47. A369/A369M-92, “Standard Specification for Carbon and
Ferritic Alloy Steel Forged and Bored Pipe for High-Temperature Service” (West Conshohocken, PA: ASTM, 1992).
48. A372/A372M-99, “Standard Specification for Carbon and
Alloy Steel Forgings for Thin-Walled Pressure Vessels”
(West Conshohocken, PA: ASTM, 1999).
49. A376/A376M-98, “Standard Specification for Seamless
Austenitic Steel Pipe for High-Temperature Central-Station
Service” (West Conshohocken, PA: ASTM, 1998).
50. A381-96, “Standard Specification for Metal-Arc-Welded
Steel Pipe for Use with High-Pressure Transmission Systems” (West Conshohocken, PA: ASTM, 1996).
51. A387/A387M-99, “Standard Specification for Pressure Vessel Plates, Alloy Steel, Chromium-Molybdenum” (West Conshohocken, PA: ASTM, 1999).
52. A389/A389M-93 (1998), “Standard Specification for Steel
Castings, Alloy, Specially Heat-Treated, for Pressure-Containing Parts, Suitable for High-Temperature Service” (West
Conshohocken, PA: ASTM, 1998).
53. A403/A403M-98, “Standard Specification for Wrought
Austenitic Stainless Steel Piping Fittings” (West Conshohocken, PA: ASTM, 1998).
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54. A409/A409M-95ae1, “Standard Specification for Welded
Large Diameter Austenitic Steel Pipe for Corrosive or HighTemperature Service” (West Conshohocken, PA: ASTM,
1995).
55. A420/A420M-96a, “Standard Specification for Piping Fittings of Wrought Carbon Steel and Alloy Steel for Low-Temperature Service” (West Conshohocken, PA: ASTM, 1996).
56. A426-92 (1997), “Standard Specification for Centrifugally
Cast Ferritic Alloy Steel Pipe for High-Temperature Service”
(West Conshohocken, PA: ASTM, 1997).
57. A447/A447M-93 (1998), “Standard Specification for Steel
Castings, Chromium-Nickel-Iron Alloy (25-12 Class), for
High-Temperature Service” (West Conshohocken, PA:
ASTM, 1998).
58. A449-93, “Standard Specification for Quenched and Tempered Steel Bolts and Studs” (West Conshohocken, PA:
ASTM, 1993).
59. A450/A450M-96a, “Standard Specification for General
Requirements for Carbon, Ferritic Alloy, and Austenitic
Alloy Steel Tubes” (West Conshohocken, PA: ASTM, 1996).
60. A451-93 (1997), “Standard Specification for Centrifugally
Cast Austenitic Steel Pipe for High-Temperature Service”
(West Conshohocken, PA: ASTM, 1997).
61. A453/A453M-99, “Standard Specification for High-Temperature Bolting Materials, with Expansion Coefficients
Comparable to Austenitic Stainless Steels” (West Conshohocken, PA: ASTM, 1999).
62. A455/A455M-90, “Standard Specification for Pressure Vessel Plates, Carbon Steel, High-Strength Manganese” (West
Conshohocken, PA: ASTM, 1990).
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63. A473-98, “Standard Specification for Stainless Steel Forgings” (West Conshohocken, PA: ASTM, 1998).
64. A487/A487M-93 (1998), “Standard Specification for Steel
Castings Suitable for Pressure Service” (West Conshohocken,
PA: ASTM, 1998).
65. A508/A508M-95, “Standard Specification for Quenched
and Tempered Vacuum-Treated Carbon and Alloy Steel Forgings for Pressure Vessels” (West Conshohocken, PA: ASTM,
1995).
66. A511-96, “Standard Specification for Seamless Stainless
Steel Mechanical Tubing” (West Conshohocken, PA: ASTM,
1996).
67. A515/A515M-92 (1997), “Standard Specification for Pressure Vessel Plates, Carbon Steel, for Intermediate and HigherTemperature Service” (West Conshohocken, PA: ASTM,
1997).
68. A516/A516M-90, “Standard Specification for Pressure Vessel Plates, Carbon Steel, for Moderate and Lower-Temperature Service” (West Conshohocken, PA: ASTM, 1990).
69. A517/A517M-93 (1998), “Standard Specification for Pressure Vessel Plates, Alloy Steel, High-Strength, Quenched and
Tempered” (West Conshohocken, PA: ASTM, 1998).
70. A524-96, “Standard Specification for Seamless Carbon
Steel Pipe for Atmospheric and Lower Temperatures” (West
Conshohocken, PA: ASTM, 1996).
71. A533/A533M-93 (1998), “Standard Specification for Pressure Vessel Plates, Alloy Steel, Quenched and Tempered,
Manganese-Molybdenum and Manganese-MolybdenumNickel” (West Conshohocken, PA: ASTM, 1998).
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72. A537/A537M-95e1, “Standard Specification for Pressure
Vessel Plates, Heat-Treated, Carbon-Manganese-Silicon
Steel” (West Conshohocken, PA: ASTM, 1995).
73. A540/A540M-98, “Standard Specification for Alloy-Steel
Bolting Materials for Special Applications” (West Conshohocken, PA: ASTM, 1998).
74. A541/A541M-95, “Standard Specification for Quenched
and Tempered Carbon and Alloy Steel Forgings for Pressure
Vessel Components” (West Conshohocken, PA: ASTM,
1995).
75. A542/A542M-99, “Standard Specification for Pressure Vessel Plates, Alloy Steel, Quenched and Tempered, ChromiumMolybdenum, and Chromium-Molybdenum-Vanadium”
(West Conshohocken, PA: ASTM, 1999).
76. A563-97, “Standard Specification for Carbon and Alloy
Steel Nuts” (West Conshohocken, PA: ASTM, 1997).
77. A570/A570M-98, “Standard Specification for Steel, Sheet
and Strip, Carbon, Hot-Rolled, Structural Quality” (West
Conshohocken, PA: ASTM, 1998).
78. A573/A573M-93a (1998), “Standard Specification for
Structural Carbon Steel Plates of Improved Toughness” (West
Conshohocken, PA: ASTM, 1998).
79. A587-96, “Standard Specification for Electric-ResistanceWelded Low-Carbon Steel Pipe for the Chemical Industry”
(West Conshohocken, PA: ASTM, 1996).
80. A671-96, “Standard Specification for Electric-FusionWelded Steel Pipe for Atmospheric and Lower Temperatures” (West Conshohocken, PA: ASTM, 1996).
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81. A672-96, “Standard Specification for Electric-FusionWelded Steel Pipe for High-Pressure Service at Moderate
Temperature” (West Conshohocken, PA: ASTM, 1996).
82. A691-98, “Standard Specification for Carbon and Alloy
Steel Pipe, Electric-Fusion-Welded for High-Pressure Service
at High Temperatures” (West Conshohocken, PA: ASTM,
1998).
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Chapter 16:Refinery Operations and
Overview
Objectives
Upon completing this chapter, you will be able to do the following:
•
State the components of an optimal corrosion program in a refinery
•
State the principal reason for a refinery’s existence
•
Explain the economic factors that affect corrosion control measures in a refinery
•
Explain the safety and environmental regulations affecting the
refining process and where to find the details concerning them
•
Explain the components of an effective corrosion control program
•
Explain the tradeoffs between economy and reliability, including
the process’s effect on equipment and the equipment’s effect on
the process
•
Describe the differences between hydroskimming refineries and
conversion refineries, including typical equipment and processes
employed by each
•
Given a system flow diagram of a typical refinery and a list of
components/processes, match the items on the list with the
appropriate components on the diagram
•
Given a diagram of a system distillation tower and a list of components/processes, match the items on the list with the appropriate components on the diagram
•
Given a system flow diagram of a catalytic cracking unit and a
list of components/processes, match the items on the list with the
appropriate components on the diagram
•
Explain unsaturated products of catalytic cracking and how they
are processed into useable products
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Refinery Operations and Overview
•
Describe at least one supporting refining process
•
List typical utility units in a refinery
•
Discuss process interactions with corrosion, including how such
interactions abruptly change with process changes and change
over time
•
Describe how operations affect equipment integrity.
16.1 Introduction
Maintaining the integrity of process equipment and achieving safe
and profitable operations require a balance of operating objectives
and an understanding of operations and corrosion interactions.
Optimizing corrosion control in refineries includes metallurgical
upgrading, the use of corrosion inhibitors or water washing, and
other operational or maintenance procedures. Several of these
factors are related to the operating objectives of the individual
refinery and the processes and feedstock used to realize these
objectives. Maintaining process equipment and producing safe and
profitable operations require an understanding of operations and the
corrosion factors presented by them.
Inspection, engineering, operations, and maintenance personnel
have a role in maintaining equipment and implementing corrosion
control measures.
16.2 Refinery Operating Objectives
A refinery's fundamental goal is to maximize its contribution to
corporate profitability consistent with safe, environmentally
responsible operations. This goal impacts many decisions in the
design and maintenance of the facility.
A light, clean feedstock may provide a product blend required for a
target market and could minimize capital investment since
sophisticated upgrading and clean-up processes would not be
needed. A target market with a high demand for motor gasoline and
distillate fuels might justify a higher investment and more complex
upgrading facilities, particularly when low-quality, low-cost heavy
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feedstocks are used. These are often corrosive, requiring the use of
high-alloy materials and other costly corrosion controls.
A company's marketing decisions are driven by economic
considerations, which influence the level of capital investment, the
process employed, the feedstocks to be processed, the products
made, and the design basis of equipment. For example, a refinery
intending to produce lubricating oil will require equipment designed
for specialized processing. Other facilities may produce and sell
precursor products, which can be used in fuels or lubes upgrading,
the production of petrochemicals, etc.
Operating safety and environmental protection considerations
impact how plants are designed and operated. Examples of
regulations and standards addressing these issues as they relate to
refinery equipment are included in Table 16.1 .
Table 16.1: Regulations and Standards Related to Refinery
Equipment Integrity
Regulation/Standard
OSHA 1910.119j
API 510
API 570
API 650, 651, 652, 653
API RP530
NBIC
ASME Boiler and Pressure
Vessel Code
ASME Piping Code
NACE RP0170
NACE SP0472
NACE RP0296
Subject
Mechanical integrity
programs
Inspection, repair, and re-rating of pressure vessels
Inspection and repair of piping
Design, inspection, repair, cathodic protection of
tankage
Design of fired heaters
National Board code covering inspection and repair of
pressure vessels
New pressure vessel design, fabrication, and inspection
New piping design, fabrication, and inspection
Prevention of polythionic acid stress corrosion cracking
Prevention of cracking of CS welds
Inspection, fabrication, and repair of equipment in wet
H2S service
Equipment monitoring, inspection, and corrosion control programs
that comply with the prevailing regulatory requirements and
refinery objectives should be developed. These tasks are usually the
responsibility of the inspector and the materials, corrosion,
equipment, or facilities engineers. The challenge involves
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Refinery Operations and Overview
developing an understanding of these problems and producing a
monitoring, inspection, and corrosion control program that complies
with the pertinent regulatory requirements and facility objectives.
Properly formulated, these programs can be used to identify
problems before they impact safety or the environment.
Equipment reliability is an issue, of course, whether or not it directly
impacts safety or environmental concerns. Unplanned outages are
expensive, possibly costing millions in production loss and the
effect on related equipment. Because of this factor, the degree of
equipment reliability is influenced by the economic goals of the
refinery. Generally speaking, higher reliability comes with an
attendant cost, and it is possible to over-engineer a facility to the
point of negating any positive contribution toward company profits.
Companies under pressure to minimize capital investment,
experiencing limited capacity, or under the influence of a cyclical
business environment may accept somewhat lower equipment
reliability. On the other hand, companies strongly dependent on
predictable equipment performance, low operating costs, and/or a
high level of process integration may not be able to afford an
unplanned shutdown. These companies will elect to ensure reliable
operations by using:
•
More durable alloys
•
Increased monitoring
•
Process additives.
16.3 Refining Process Overview
Refineries vary in complexity and types of processes employed to
manufacture the required products. Simple refineries
(hydroskimming refineries) may produce fuels from basic crude
distillation with limited upgrading and product clean-up.
Hydroskimming refineries limit the production of heavy fuel oils by
running lighter crude feeds, which are often higher in cost.
Common processes include:
•
Atmospheric distillation
•
Crude light ends separation
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•
Vacuum distillation
•
Hydrotreating (naphtha/distillates)
•
Catalytic reforming
•
Merox treating
•
Amine treating
•
Sour water stripping
•
Sulfur plant
•
Utilities
•
Oil movement/storage.
Complex refineries (conversion refineries) may use various
conversion and upgrading processes to make larger quantities of
valuable lighter fuels from relatively heavy, low-cost streams. A
large number of product clean-up facilities are provided since the
crudes are generally high in sulfur and other contaminants. In
addition to the processes found in hydroskimming refineries,
conversion refinery processes include hydrotreating for gas oils,
caustic treating, fluid catalytic cracking, coking, alkylation,
hydrocracking, and steam reforming.
Specialty processes may be used to manufacture lubricating oils.
Nearly all refineries operate supporting utilities processes, which
provide steam, cooling water, and clean fuels for internal use.
Feedstocks and products are handled in a complex arrangement of
piping and tankage.
Common refinery processes are summarized in Table 16.2 .
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Table 16.2: Summarizes common refinery processes
Basic Distillation
Atmospheric distillation
Crude light ends separation
Vacuum distillation
Desulfurization
Hydrotreating
Naphtha
Distillates
Gas oils
Residuum
Supporting Processes
Amine treating
Caustic treating
Sour water stripping
Sulfur recovery
H2manufacture (steam reforming)
Pressure swing absorption
MTBE production
Lube Processing
Lube extraction
Dewaxing
Deasphalting
Lube hydrotreating
Light Products Upgrading
Catalytic reforming
Alkylation
Isomerization
Heavy Oil Upgrading
Hydrocracking
Fluidcatalytic cracking and light ends
separation
Coking and light ends separation
Thermal cracking
Visbreaking
Utilities
Cooling water
Boiler feedwater treatment
Steam generation
Flare systems
Cogeneration facilities
Oil Movement and Storage
Product blending
Piping
Tanks
Pressurized spheres
Figure 16.1 is a diagram showing the system flow of a conversion
refinery. The types and order of processes in a refinery vary and
dictate the end products of facility operation. Figure 16.2 is a
diagram of a simple distillation tower, and Figure 16.3 is a similar
diagram of a catalytic cracking unit.
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Figure 16.1 System Flow of a Conversion Refinery
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Figure 16.2 Distillation Tower
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Figure 16.3 Catalytic Cracking Unit
Typically, crude oil or blends of crudes are first fractionated at
elevated temperature in atmospheric distillation units, which
separate them into gas, naphtha, light distillates (diesel and
kerosene), light gas oils, and atmospheric residuum. Residuum is
usually sent to a vacuum distillation unit, which primarily separates
a range of heavy gas oils or lube feedstocks.
The light streams from crude distillation are separated in light ends
facilities into fuel gas (methane and ethane), LPG, butane, and a
variety of other hydrocarbons, such as C3, C4, and C5 products.
Fuel gas is often used within the refinery as fuel for the plant's fired
process heaters and boilers or used in cogeneration operations to
generate steam and electric power.
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The naphtha stream is processed in a catalytic reforming unit
following hydrotreating to reduce sulfur, which is a reforming
catalyst poison. Reforming increases the octane value of fuels.
Hydrogen is a byproduct of catalytic reforming and is often used in
hydrotreating processes since they consume hydrogen as part of
their reactions.
Steam reforming units produce hydrogen for refineries that have a
high hydrogen demand due to sulfur removal and hydro-conversion
needs. In hydrogen plants, a light hydrocarbon, such as methane,
natural gas, or naphtha, is reacted with steam in catalyst-filled fired
heater tubes to produce hydrogen, with carbon dioxide produced as
a by-product. The CO2 is removed by gas treating or pressure swing
absorption (PSA) processes, providing higher purity hydrogen for
hydrotreating and hydrocracking processes.
Distillate fuels, which are heavier than naphtha, from both crude
distillation and upgrading processes are usually hydrotreated to
reduce their sulfur content and then blended to produce kerosene,
diesel fuel, and jet fuel.
The gas oil streams from atmospheric and vacuum distillation may
be blended into fuel oils at refineries that have no further
processing, but many refineries use them as feeds to catalytic
cracking units and hydrocracking units to produce additional
gasoline and middle distillate fuels. These fuels are sometimes
hydrotreated to reduce the sulfur level.
Products from catalytic cracking units are unsaturated (hydrogen
deficient), meaning they have fewer hydrogen atoms per carbon
atom, which results in undesirable properties. The following steps
remedy this condition:
•
The lightest products are separated and blended into fuel gas.
•
Gasoline-range materials may be reformed by processing in
alkylation or isomerization units to provide octane-improving
blending components for motor fuel.
•
Heavier products may be hydrotreated, used as hydrocracker
feeds, or blended into fuel oil.
Vacuum fractionator bottoms may be blended into fuel oils or
upgraded in coking processes. These thermal cracking processes
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operate on the principal of carbon rejection in which the coking
process releases excess carbon in the form of coke. In coking, heavy
hydrocarbons are cracked producing lighter hydrocarbons and
petroleum coke, which is a saleable product. Coker products are
usually processed in fractionation and light ends facilities similar to
those used for fluid catalytic cracking unit products.
Vacuum distillation unit products may also be used as feedstocks for
lube oil production. High-value lube base stocks (raffinate) are
extracted from these streams using solvent extraction. Low-value
extract is often used as feed to catalytic cracking units while the
raffinate is hydrotreated, dewaxed, and then blended with various
additives to make a range of lubricating oils with a variety of
properties.
Hydroprocessing is widely used in refineries. It refers to two basic
types of operations—hydrodesulfurization (and denitrification) and
hydroconversion—in which the stream being processed and the
hydrogen are heated, combined, and reacted in a catalyst-filled
vessel or reactor. Hydroprocessing involves:
•
Reacting the hydrogen and sulfur to form hydrogen sulfide,
which is removed in the recycle hydrogen stream and condensed
sour waters from the unit separators and strippers.
•
Processing heavier oil streams at higher pressures and temperatures than lighter oil streams.
In hydrocracking, the most common hydroconversion process, not
only is sulfur removed, but heavier oils are also converted to lighter,
higher-value products.
Supporting refinery processes include:
•
Amine treating to remove hydrogen sulfide from fuel gas.
•
Recycling hydrogen gas from hydrotreating units.
•
Sour water strippers to reduce H2S and ammonia content of
refinery process condensates so these waters can be reused in the
plant or disposed of.
•
Sulfur plants used to convert H2S into elemental sulfur, which is
sold to manufacturers of sulfuric acid or fertilizers.
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•
A number of utility units are found in refineries including:
•
Cooling water systems
•
Steam generation facilities
•
Flare systems
•
Waste water treatment facilities.
16.4 Process Interactions with Corrosion
The high level of process integration within a refinery means farreaching effects when feed or process changes are considered or
when corrosion control measures are being evaluated. Changing a
feedstock to one with a higher sulfur content, for example, may
overload the sulfur removal capabilities of hydrotreating, amine
treating, and sulfur recovery plants and could increase corrosion in
the distillation units, hydrotreaters, amine treating units, catalytic
crackers, cokers, and sour water strippers.
Gradual process changes, such as increases in temperature or
pressure, can dramatically increase corrosion rates. For example,
increased pressures may increase the solubility of corrosive species
in water or raise hydrogen partial pressures to the point where hightemperature hydrogen attack becomes a concern in hydrotreating
units.
Corrosion control measures can also affect equipment throughout a
refinery, such as:
•
Neutralizing amines, which are used to control corrosion by
acidic chloride condensates and may result in fouling and corrosion of equipment by the neutralizer salt.
•
Filming inhibitors, which can become serious catalyst poisons in
downstream processes due to their high nitrogen content.
•
Oxygenated water, which may be used for water washing to mitigate sour water corrosion, resulting in an increased corrosion
rate.
Process improvements may also have an impact on corrosion,
including:
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•
An improved catalyst in a hydrotreating process, which can
increase the amount of hydrogen sulfide that affects corrosion in
high-temperature systems and sour water systems.
•
Operational changes and catalyst improvements, which can also
increase denitrogenation of feeds, dramatically increasing corrosion due to higher ammonium bisulfide levels in the sour water
system.
Ongoing communication among plant personnel is essential to
ensure evaluation of changing operational processes and
development of a program to monitor and control corrosion. The
roles of equipment engineers, such as metallurgists, inspectors, and
corrosion and mechanical engineers, are varied. These individuals
must:
•
Understand the factors affecting equipment reliability and degradation
•
Ensure materials are selected and installed correctly
•
Establish corrosion monitoring and control programs
•
Assess and report equipment condition
•
Ensure compliance with codes and standards.
Plant operators and supporting process engineers have roles in
equipment integrity, which affects facility operations in several
ways. Reliable equipment is generally safer, cleaner in terms of
environmental considerations, and ultimately more profitable.
In a similar way, refinery operations affect equipment integrity.
Feedstocks and the operating conditions under which they are
processed influence measures employed to limit corrosion, and
ultimately the life of the equipment.
For these reasons, it is necessary that corrosion specialists and
operations personnel establish communication programs concerning
the following issues:
•
Identify operating unit basis and constraints
•
Operation within equipment design limits
•
Operation within agreed conditions established by material degradation concerns
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Refinery Operations and Overview
•
Communicate changes in operating conditions, feedstocks, etc.
•
Carry out necessary corrosion monitoring and control measures.
Additionally, maintenance personnel must ensure overall equipment
integrity. This must include engineering repairs to overcome
equipment design problems; ensuring repairs and maintenance
according to specifications; and providing information on
equipment failures.
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Chapter 17:Failure Analysis in
Refineries
Objectives
Upon completing this chapter, you will be able to do the following:
•
Discuss the purpose of a failure analysis
•
Identify the four categories of service failures for plant equipment
•
Define component failure and identify causes of failure in refineries
•
Identify failure mechanisms common in refinery environments
•
Identify and discuss the primary phases that typically constitute
a failure analysis
•
Identify and describe types of nondestructive testing techniques
used in refineries
•
Discuss the destructive sectioning process
•
Identify characteristic patterns of certain fractures that can be
detected visually (macroscopically)
•
Discuss microscopic examination using both an optical microscope and a scanning electron microscope (SEM)
•
Identify characteristic patterns of certain fractures that can be
detected microscopically
•
Discuss types of mechanical testing, such as chemical analysis
and hardness testing
•
Discuss methods involved in determining the root cause of a failure
•
Identify types of recommendations that may be made to avoid a
recurrence of the failure.
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Failure Analysis in Refineries
17.1 Introduction
The main objective of a proper failure analysis is to determine the
root cause of a failure and, based on that conclusion, develop a
corrective action to prevent similar future failures. As part of the
failure analysis, factors contributing to the failure should be
assessed. Several analytical techniques may be used to conduct a
failure analysis, including visual examination, photographic
documentation, component sectioning, nondestructive testing, and
microstructural and fractographic examination.
In general, service failures may arise from a variety of causes. For
most refinery equipment, these causes can be grouped into four
categories:
•
Design
•
Alloy processing and fabrication
•
In-service deterioration
•
Misuse.
When a component has failed, it can no longer continue to
satisfactorily perform its intended function. This can be due to a
fracture, excessive deterioration, corrosion, wear, or excessive
deformation. Failures can occur as a result of normal consumption
of component life or unexpected operational upsets, which cause
premature failure.
Depending on the size and type of failed component, a failure
analysis can either be performed using conventional techniques in a
metallurgical laboratory or in the field. Field analysis typically
involves a combination of visual examination and other
nondestructive examination methods. Nondestructive testing is
normally performed on larger, more costly components, such as
pressure vessels, which will ultimately be repaired rather than
removed from service.
A number of failure mechanisms occur in industrial service. The
potential for a particular mechanism to become active depends on
several factors, including:
•
The material involved
•
The environment
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•
The metal temperature
•
Stresses (static and cyclic) on the component
•
The age of the component.
Some of the failure mechanisms, which are commonly found in
refining environments, were examined in Chapter 1, Corrosion and
Other Failures. They include the following:
•
General corrosion
•
Localized corrosion (pitting, crevice corrosion)
•
Erosion-corrosion
•
Stress corrosion cracking (SCC)
•
Fatigue
•
Creep
•
Wet H2S damage
•
High-temperature hydrogen attack (HTHA)
•
Temper embrittlement
•
Sigma phase formation.
Of these mechanisms, corrosion-related problems are responsible
for most of the failures occurring in industry. Corrosion can be the
easiest mechanism to properly identify, sometimes requiring only
visual inspection and possibly a chemical analysis of corrosion
deposits, if present. However, with fractures, analysis of all data
collected from the fracture surfaces, metallurgical sections, and
other tests is required to properly identify the failure mode.
17.2 Procedural Approach and Test
Methods
The most important steps in conducting a failure analysis are:
•
Developing a procedure to analyze the failure
•
Following the procedure.
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Failure Analysis in Refineries
Too often the inspector or plant engineer will quickly section and
remove the failed component without documenting its appearance
or position, losing valuable information.
Although failure analyses can be very individualized, the primary
phases that typically constitute the investigation are as follows:
•
Collection of background information concerning the failure,
including component drawings and material specifications along
with operational information.
•
Preliminary examination of the failed component, ideally while
still in place in the plant. Photographic documentation of the
component as well as surrounding conditions should be performed.
•
Nondestructive testing, which can include field metallographic
replication, hardness and chemical analysis, ultrasonic testing,
magnetic particle testing or dye penetrant testing can be performed when deemed necessary. In addition, all dimensional
testing should be performed prior to sectioning.
•
If sectioning is needed, a cutting plan should be developed to
protect critical portions of the failure as well as to minimize
machining.
•
Macroscopic examination of the fracture surfaces.
•
Microscopic examination, which may include using both an
optical microscope as well as a scanning electron microscope
(SEM).
•
Determination of failure mechanisms involved.
•
Additional testing which may include chemical analysis and tensile, hardness, or charpy impact testing.
•
Determination of the root cause of the failure.
•
Development of recommendations to avoid a recurrence of a
similar failure.
17.2.1 Background Information
The first portion of the analysis involves the collection of all
pertinent information regarding the failed component, including
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drawings, material specifications, and operational data. In addition,
information gathered should include eyewitness accounts describing
the events and conditions that preceded and followed the failure.
These observations will help indicate whether an operational upset
contributed to the failure or if any action was performed following
the failure, such as spraying water on a fire, which could have an
impact on the analysis.
Component history includes:
•
Time in service
•
Normal operating conditions
•
Previous problems or failures
•
Anticipated loading on the component
•
Upset conditions.
Previous inspection history should be examined to evaluate wall
loss trends due to corrosion. Also, metallurgical reports providing
data regarding the condition of the component should be evaluated.
17.2.2 Initial Examination
Ideally, in most cases, the investigator should attempt to examine
the failure immediately following its discovery, while evidence is
still in place. This will allow for the most thorough documentation
of the failure in terms of its location, orientation, and surroundings.
Critical dimensions, observations, and eyewitness testimony should
be collected at this time. Photography should accompany the initial
inspection along with documentation of all pertinent features of the
failure as well as surrounding conditions. If sample removal is to be
performed, both on site and in the laboratory, areas to be removed
should be labeled and, if possible, photographed. The investigator is
responsible for ensuring that the samples to be removed are suitable
for their intended purpose and that they will adequately represent
the failure’s characteristics.
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Failure Analysis in Refineries
17.2.3 Nondestructive Testing
Nondestructive testing is almost always preferred to destructive
testing. In many situations, the failed component cannot be removed
for laboratory analysis, primarily due to the economic advantage of
repairing equipment, rather than replacing it. In these cases, an insitu analysis is conducted to provide as much information as
possible, without further damaging the equipment.
As with any failure, visual examination, accompanied by
photographic documentation, is normally performed first to provide
information regarding the appearance of the damage. Following
visual examination, a variety of techniques can be employed to
interpret the failure mode. These techniques include the following:
•
Surface deposit analysis
•
Field metallographic replication (FMR)
•
Hardness testing
•
Chemical analysis
•
Radiography (RT)
•
Magnetic particle inspection (MPI)
•
Dye penetrant testing (PT)
Of the seven techniques listed, the last three are primarily used in
the detection of cracking and to establish the extent of damage. The
first four techniques are used to characterize the damage present.
17.2.3.1 Surface Deposit Analysis
During the analysis of a failure, establishing the chemical
composition of surface deposits and oxides can provide valuable
information in determining if a particular corrosive mechanism has
been involved in the failure. Typically, these deposits are either
scraped or stripped off the surface using tape. The deposits are then
stored and labeled to prevent any further interaction with the
environment. They are then analyzed using energy dispersive
spectroscopy (EDS), microprobe analysis, or x-ray florescence
(XRF).
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17.2.3.2 Field Metallographic Replication (FMR)
FMR is used to microstructurally evaluate the area involved with the
failure in an attempt to identify the damage mechanism. Replication
involves progressively preparing the surface of the component
through grinding and polishing to obtain approximately a 1 micron
surface finish. The surface is then normally etched to enhance the
relevant microstructural features present. A thin piece of acetatebased tape is then laid over the polished surface after wetting the
surface with acetone. The replica tape essentially melts into the
surface, and the result is a negative image fingerprint of the
microstructure.
This replica tape is examined immediately following its removal,
providing immediate results concerning the failure. Documentation
of the replica is normally carried out using an optical microscope at
magnifications up to 1000x. The replica can also be evaluated by
using the scanning electron microscope (SEM) at higher
magnifications, with greater depth of field.
Damage mechanisms, such as creep, hydrogen attack, fatigue, and
stress corrosion cracking, can be correctly identified. In addition,
fabrication-related discontinuities, such as lack of fusion and
porosity, can also be distinguished from actual in-service problems.
17.2.3.3 Hardness Testing
Ferritic alloys, due to their crystal structure, undergo changes in
hardness during elevated temperature exposure. Welding operations
and changes in process temperatures can alter the hardness of these
alloys.
Field hardness testing is used to quantify these changes and to
establish if temperature variations or, in some cases, a lack of an
adequate post welding heat treatment (PWHT) contributed to the
failure.
Several portable instruments are available to assess material
hardness on equipment. If a measurement for base metal hardness
only is required, then one of the Brinell testers can be used. Since
the size of the indent sometimes exceeds the width of the heataffected zone (HAZ), this instrument cannot be used to measure
HAZ hardnesses.
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Failure Analysis in Refineries
In cases where a form of stress corrosion cracking is suspected on
ferritic alloys, such as sulfide stress cracking or caustic cracking,
hardness values measured in the weld and HAZ can give an
indication of the effectiveness of the PWHT performed. In general,
as these welded regions exceed a hardness of 200 BHN (Brinell
Hardness Number) their susceptibility to SCC increases. Ferritic
materials exposed to typical PWHT temperatures have hardnesses
below 200 BHN.
In a situation where equipment overheating is suspected due to fire
or other process upset conditions, hardness testing can be used to
map areas affected by the heat. Depending on the heating and
cooling scenario, the material may have hardened, softened, or
remained unchanged.
17.2.3.4 Chemical Analysis
Positive material identification (PMI) has recently become an
important issue in plants due to failures, which have occurred as a
result of the wrong material being placed in service. For example,
carbon steel, inadvertently placed in service where a higher alloyed
material is required, can fail prematurely. As part of an analysis to
determine the cause of failure, in-situ chemical analysis can be
performed.
There are two major categories of devices used to perform PMI.
They are optical emission spectroscopy (OES) and x-ray
fluorescence (XRF). Comparing the two, the XRF instrument is
compact and contains a low-level radioactive isotope. The isotope
must be licensed and renewed every few years. It can, with special
probes, be used at temperatures up to 800F. Since the OES
instrument operates by exciting electrons using an electric spark, it
requires no radioactive sources. The OES instrument can be used at
temperatures up to 750F to detect heavier alloying elements. At
lower temperatures, OES can also quantify carbon, phosphorus,
aluminum, sulfur, and silicon.
17.2.3.5 Magnetic Particle Inspection (MPI)
During the course of a failure analysis, MPI is used to determine the
extent of any damage found on the surface of the component. The
technique is used on ferromagnetic materials, such as carbon steel
and Cr-Mo steels, to detect surface breaking discontinuities. It
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cannot be used to test materials that cannot be magnetized, such as
austenitic stainless steels, copper, brass, titanium, aluminum, or
lead.
The principle involves inducing an alternating current or direct
current magnetic field between two poles on a hand-held yoke and
spraying a solution of iron particles, either dry or in solution, onto
the test piece. Discontinuities on the surface will break the induced
magnetic field, causing a flux leakage. The iron particles will pile
up along this area of flux leakage enabling the operator to detect any
discontinuities present visually or using a black light in the case of
fluorescent particles.
The two basic methods of magnetic particle testing are the wet
method and the dry method.
17.2.3.6 Wet Method
Magnetic particles are suspended in oil or water. They can be visible
as black or red, or they can be fluorescent. Fluorescent particles are
examined under a black (near-ultraviolet) light, which offers greater
sensitivity for detecting fine cracks. Wet fluorescent magnetic
particle inspection (WFMT) has proved to be the most effective
method for detecting stress corrosion cracks when optimum
sensitivity is needed. WFMT is particularly useful in columns and
vessels because the black light, which is used to highlight the
cracks, also serves as a light source.
17.2.3.7 Dry Method
With the dry MPI method, no liquid vehicle is present. Dry powders
are available in black, red, or white to provide contrast to the part
being inspected. MPI is not always practical because it requires a
source of electrical power.
Surface preparation to remove scale and dirt is important to the
success of this method. Tight, shallow cracks often will not show up
unless abrasive blast cleaning, wire wheel brushing, or grinding
cleans the surface to a shiny finish. Although MPI is intended for
surface inspection, it will frequently detect defects that are slightly
below the surface. Therefore, the tests results must be carefully
interpreted.
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17.2.3.8 Dye Penetrant Testing (PT)
This technique is primarily designed for use on non-ferromagnetic
materials but is frequently used on ferromagnetic materials as well.
It is a relatively easy technique to use and involves spraying a red
dye solution onto the test piece. Any surface-breaking discontinuity
will fill with this dye due to capillary action. After a length of time,
the dye is wiped off the workpiece, and a white developer is sprayed
onto the surface. The developer will draw out the dye contained
inside any discontinuities present, making visual detection possible.
In order for penetrant inspection to be effective, the surface must be
clean and free of scale. In addition, adequate penetration time for the
dye must be provided. Penetration time is strongly influenced by
temperature.
It should be noted that PT is less sensitive than MPI at detecting
tight cracks or cracks that have an oxide scale within them, such as
carbonate stress corrosion cracks. Therefore, when working with
ferromagnetic materials it is recommended to use MPI whenever
possible.
17.2.3.9 Sectioning
In many cases, particularly when a component has failed and will
subsequently be replaced, destructive sectioning is performed to
provide samples for microstructural and fractographic analysis.
Prior to sectioning, the procedure for the failure analysis should be
developed because once the component is sectioned, other tests,
such as establishing part dimensions, cannot be performed
accurately.
Rough sectioning can be performed by torch cutting as long as the
cut is kept at least 6 inches from any critical portions of the
component, such as the fracture, since high temperatures can alter
the microstructure, making correct interpretation difficult. Final
sectioning is performed using a band saw, cut-off wheel, or a
diamond-bladed circular saw for very precise cuts. The band saw
can be used with or without cooling fluid, and it is recommended
that if chemical analysis is to be performed on surface or crack
deposits, the dry method be performed.
Once the samples are removed, they can either be prepared for
microstructural analysis by polishing and etching or the fracture
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surface can be prepared for further macroscopic and microscopic
analysis.
17.2.4 Macroscopic Examination of Fracture
Surfaces
Fracture structures are typically examined initially by visual means
or by using a low-magnification stereo microscope. Failure modes
have characteristic patterns on their fracture surfaces which enable
the investigator to identify certain mechanisms. Fatigue failures, for
instance, typically have clamshell patterns, or beach marks, on their
surface, which not only indicate the potential damage mechanism,
but also indicate where the initiation point of the crack is located.
Overload failures also show characteristic patterns on their surfaces,
which help the investigator identify the fracture initiation point.
Normally the fracture is documented initially at low magnifications
using a 35-mm or Polaroid MP-4 camera.
17.2.5 Microscopic Examination
In some cases, microscopic examination of either the through-wall
microstructure or the fracture surface is necessary to determine the
cause(s) of failure. Most microstructural analysis is performed using
an optical microscope at magnifications ranging from 10x to 1000x.
The general condition of the microstructure is normally compared to
what would be considered a typical microstructure for the alloy
being examined to determine if any evidence of overheating is
present. Cracking, or other damage present, is examined to
determine if the propagation mode was intergranular or
transgranular. Based on the mode of failure, many types of damage,
such as stress corrosion cracking (SCC) can be identified.
The SEM, which is more powerful than an optical microscope, may
also be used. In many cases, it is the most important part of the
failure analysis because it can provide final confirmation as to the
damage mechanism responsible for the failure.
Fracture surfaces, in many cases, are covered with an oxide film or
deposit. As mentioned previously, if it is believed that these surface
deposits may provide some insight into the mechanism responsible
for the failure, they can be chemically analyzed using energy
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Failure Analysis in Refineries
dispersive x-ray spectroscopy (EDS) or x-ray diffraction. EDS is
considered semi-quantitative, in that elements are analyzed and
quantified, but generally the data is not compared to laboratory
standards. Therefore, this technique is not typically used for positive
material identification.
When the deposit or oxidation product is present, it should be
removed following EDS so that the underlying metal can be
examined with the SEM. Electrochemical techniques as well as
mechanical stripping of the deposit using tape can be used to clean
the fracture surface.
Examination is performed at magnifications as low as 15x-20x and
up to 5000x-10,000x. Fracture features are examined and initiation
sites are identified, if possible. As with macroscopic features,
microscopic features, such as striations, river patterns, cleavage, and
ductile dimple rupture patterns offer much insight into how a
component failed. These features can help determine whether the
component failed in a ductile versus brittle fashion or if the failure
was progressive, such as with fatigue, SCC, or creep.
17.2.6 Fracture Appearance
17.2.6.1 Ductile Fracture
Most overload failures, which occur in components, take place in a
ductile mode. This type of failure normally involves plastic
deformation, which is usually accompanied by necking. During this
plastic extension of the component, microstructural cracking of
included particles occurs, creating microvoids.
Fractographic analysis using an SEM will normally reveal those
equiaxed dimples in samples that have failed due to a tensile
overload. If shear-type loading initiated the failure these dimples
will appear as elongated voids, with the voids on the mating
surfaces pointing in opposite directions. If tearing caused the failure,
the elongated voids on the mating surfaces are mirror images.
17.2.6.2 Brittle Fracture
Brittle failure can occur either in a transgranular mode or an
intergranular mode. Transgranular cleavage in ferritic alloys is the
most common mechanism involving brittle fracture. This type of
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fracture is not difficult to diagnose. In most ferritic alloys, this type
of crack propagation produces a pattern of brightly reflecting facets,
which has led in the past to these failures being described as
crystalline. Microstructurally, the most characteristic feature with
transgranular cleavage is the presence of a pattern of river marks,
which consist of cleavage steps and indicate local direction of
growth.
Intergranular brittle fracture normally can easily be recognized,
although determination of the primary (root) cause of failure may be
difficult. The damage mechanisms, which may promote an
intergranular cracking path, include:
•
Fatigue
•
SCC
•
Liquid metal embrittlement (LME)
•
Hydrogen embrittlement
•
High-temperature hydrogen attack (HTHA)
•
Creep.
17.2.6.3 Fatigue Fractures
Microscopically, the surfaces of fatigue fractures are characterized
by the presence of striations. Each striation represents a single cycle
of stress. It should be noted that not every stress cycle produces a
striation. In addition, the absence of striations does not rule out the
possibility that fatigue was the damage mechanism.
17.2.6.4 Stress Corrosion Cracking
Stress corrosion cracks may be either intergranular or transgranular
in nature. The fractographic features produced when SCC
propagates in a transgranular mode are varied and can range from
cleavage to striations. When propagating in an intergranular mode,
the fracture normally has a rock candy appearance, although this can
be confused at times with hydrogen-related mechanisms in highstrength steels.
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17.2.6.5 Creep Rupture Failures
Creep-related failures are normally visually characterized by
deformation or straining prior to the actual failure and
microstructurally characterized by the presence of intergranular
voids and fissures. Normally, fractographic analysis is not
performed on creep failures as the microstructural analysis, or
surface replication, can correctly identify this mechanism.
17.2.7 Additional Testing and Analysis
17.2.7.1 Mechanical Testing
Chemical and hardness testing, which were previously addressed
during the examination of nondestructive testing are more
frequently applied in the laboratory. Although the accuracy of the
chemical analysis is approximately equal for the same type of
technique performed in the field, the hardness test data typically is
more reliable when obtained under laboratory conditions. Both
surface hardness and microhardness traverse through the wall of the
sample or across welds, and hardened layers can be accomplished.
Laboratory testing can be undertaken to establish if a deficiency in
the component’s strength or toughness contributed to the failure.
Corrosion testing can also be conducted to help understand the
component’s resistance to a particular environment.
17.2.7.2 Application of Fracture Mechanics
To predict the fracture strength of a component, or to estimate the
types and magnitudes of stresses that lead to a failure, the following
factors need to be assessed:
•
The applied loads
•
An estimation of any stress concentration present
•
The fracture toughness of the component.
The stress intensity, KI, represents the level of stress at a crack tip or
notch. The fracture toughness, KIC, is the highest value of stress
intensity that the component can withstand without fracturing. The
general expression for stress intensity is:
KI = a Y
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Where  is the nominal applied stress and a is the crack length. For
a given crack length, the stress intensity equals zero when the stress
equals zero and increases linearly with the applied stress and square
root of the crack length.
This type of approach is also used when assessing fatigue failures to
estimate the number of cycles that the component was exposed to
prior to final failure. For many engineering alloys, the rate of crack
propagation, da/dN, can be expressed as a function of the range of
stress intensity ΔKI that the crack experiences during the stress
cycle.
da/dN = CΔKIm
If the toughness of the material is known, knowing the length of a
flaw prior to final overloading can offer clues regarding the
magnitude of loading induced on the component. Conservative
estimations of toughness can be made for initial calculations. If
necessary, the material toughness can be further defined through
material testing.
17.2.8 Root Cause Analysis
Determining the root cause of a failure can be the most difficult
portion of the failure analysis. Certain failure mechanisms may
develop as a result of either another failure mechanism or a material
or fabrication discontinuity. It is the goal of the investigator to
analyze all pertinent data collected and to decide the proper order of
what precipitated the failure.
Cause analysis is the most vital part of a failure investigation. A
systematic method of processing the information obtained from the
metallurgical analysis and other sources of data leads to the:
•
Identification of the problem
•
Identification of the factors contributing to the problem
•
Development of the corrective actions required to remedy the
problem.
The failure to follow an organized analysis method can result in
random guessing of the problem, which rarely defines the precise
cause of failure and seldom solves the problem.
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Depending on the complexity of the failure, determining the root
cause may be straightforward, or it may involve backtracking
through process and inspection data until the root cause is
discovered. The fact that a pipe internally corroded does not
necessarily mean that the root cause of the failure is corrosion. It
could be related to a change in process chemistry or an improperly
specified or installed material.
17.3 Recommendations
Once all the data has been collected and analyzed, and the root
cause has been identified, recommendations are developed to avoid
a recurrence of the problem. Possible recommendations may
include:
•
Material change
•
Process change (temperature, pressure, or chemistry)
•
Change in inspection type or interval
•
Design change
•
Component replacement.
It should be remembered that not all recommendations may be
practical. A suggestion to lower the process temperature or reduce
the sulfur content of a process fluid is not a good recommendation if
the plant cannot change these parameters. Therefore, careful thought
should go into choosing the most practical and economic solution to
prevent or delay a similar failure.
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Corrosion Control in the Refining Industry
Index
A
acid runaway ............................................................................................................... 6-10
Activation
polarization ............................................................................................................. 1-7
anneal ........................................................................................................................ 15-45
auto-refrigeration .......................................................................................................... 6-6
B
bake out ..................................................................................................................... 15-44
bottoms .......................................................................................................................... 9-4
C
capped steel ............................................................................................................... 15-21
carburization ............................................................................................................... 3-26
clamshell ................................................................................................................... 17-11
clean steel .................................................................................................................. 10-16
clean steels ................................................................................................................ 10-19
cold shell ....................................................................................................................... 8-8
Concentration
polarization ............................................................................................................. 1-7
Couper-Gorman Curves ................................................................................................ 7-7
crack ............................................................................................................................ 2-18
cut points ....................................................................................................................... 2-8
D
delayed coking .............................................................................................................. 9-3
denickelfication ........................................................................................................... 1-71
dense phase ................................................................................................................... 3-6
dezincification ............................................................................................................. 1-71
dilute phase ................................................................................................................... 3-7
drawing board ........................................................................................................... 15-10
E
electrochemical concept. ............................................................................................. 15-6
Erosion ........................................................................................................................ 1-76
essential variables ..................................................................................................... 15-56
F
fat amine ..................................................................................................................... 10-5
filmer ......................................................................................................................... 13-10
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January 2010
Corrosion Control in the Refining Industry
2
filmers ......................................................................................................................... 2-25
Filming
inhibitors ............................................................................................................. 10-17
Filming amine ........................................................................................................... 13-10
fines ............................................................................................................................... 3-7
fire box quality steel plate ......................................................................................... 15-11
Fluid .............................................................................................................................. 3-3
flux
active ................................................................................................................... 15-55
neutral ................................................................................................................. 15-55
fractions ........................................................................................................................ 2-8
G
Gouging abrasion ........................................................................................................ 1-76
graphitization .............................................................................................................. 1-71
Grinding abrasion ....................................................................................................... 1-76
gunned ....................................................................................................................... 11-14
H
heat stable ........................................................................................................10-2, 10-14
Hot shell ........................................................................................................................ 8-8
hot spots .................................................................................................................... 14-23
Hydrocarbon ................................................................................................................. 2-4
hydrogen grooving ...................................................................................................... 6-10
I
immersion test ............................................................................................................. 15-7
injection point ............................................................................................................. 12-2
K
killed carbon steel ..................................................................................................... 15-11
killed steel ................................................................................................................. 15-21
L
lean amine ................................................................................................................... 10-7
Linear Rate
Law ....................................................................................................................... 1-14
M
McConomy Curves ....................................................................................................... 7-9
Motor Octane
Number ................................................................................................................... 8-2
Corrosion Control in the Refining Industry
©NACE International 2008
January 2010
3
N
Nelson Curves ............................................................................................................... 7-6
neutralization number ................................................................................................. 13-4
neutralizer ................................................................................................................. 13-16
neutralizing amine ..................................................................................................... 13-16
Non-hydrocarbon .......................................................................................................... 2-4
P
Parabolic Rate
Law ....................................................................................................................... 1-14
Passivating
inhibitors ............................................................................................................. 10-17
pile up ......................................................................................................................... 17-9
polymer ..................................................................................................................... 10-13
R
refinery steels ............................................................................................................ 15-19
reflux ........................................................................................................................... 2-16
Research Octane
Number ................................................................................................................... 8-2
residual test ................................................................................................................. 2-28
rich amine ................................................................................................................... 10-5
rimmed steel .............................................................................................................. 15-21
rock candy ................................................................................................................. 17-13
S
sensitized ................................................................................................................... 15-45
spent acid ...................................................................................................................... 6-4
W
wet H2S cracking ...................................................................................................... 10-16
©NACE International 2008
January 2010
Corrosion Control in the Refining Industry