157954060 Refining Student Manual July2011 PDF

Corrosion Control in The Refining Industry

July 2011  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.

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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.

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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

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Sulfuric Acid Alkylation Units

•

Corrosion in Hydroprocessing Units

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Catalytic Reforming Units

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Delayed Coking Units

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Amine Treating Units

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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

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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

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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

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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

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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 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 SP0472, “Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments”

H

NACE SP0296, “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”

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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 SP0294, “Design, Fabrication, and Inspection of Tanks for the Storage of Concentrated Sulfuric Acid and Oleum at Ambient Temperatures”

N

NACE SP0205, ”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 Standard 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 SP0198, “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”

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U

NACE Standard TM0169, “Laboratory Corrosion Testing of Metals”

V

NACE SP0590, “Recommended Practice for Prevention, Detection and Correction of Deaerator Cracking”

W X

NACE International Publication 34109 Crude Distillation Unit— Distillation Tower Overhead System Corrosion

Y

UNS Numbers/Composition of Alloys

Z

Glossary of Refinery Corrosion Related Terms

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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

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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

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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

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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

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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

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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) O2 + 4H+ + 4e–  2H2O O2 + 2H2O + 4e–  4OH– M+3 + e–  M+2 M+ + e–  M

hydrogen evolution oxygen reduction in acid solutions oxygen reduction in neutral or basic solutions metal ion reduction metal deposition (plating)

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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•

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 SP0198 (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 (55.6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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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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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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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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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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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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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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•

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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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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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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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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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

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Reason(s) for Selection

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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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•

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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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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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 a.

55.0 12.0 8.0 10.0 118.0

*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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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.

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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

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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 ( 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 (