Course Introduction: 

Statistics shows that the total cost of corrosion control in refineries in the US alone is estimated at $3.692 billion. Of this total, maintenance-related expenses are estimated at $1.767 billion annually, vessel turnaround expenses account for $1.425 billion annually, and fouling costs are approximately $0.500 billion annually. Significant cost reduction can be achieved with timely and appropriate corrosion inspection. Asset integrity can be enhanced with corrosion monitoring and corrosion mitigation methods such as materials selection and chemical treatment.

This 6-day corrosion short course covers corrosion inspection, corrosion monitoring and corrosion control in oil refineries.

This corrosion short course is available for on-site training, online and distance learning worldwide. It can also be customized to meet the specific needs of your organization.

Course Objectives:

Upon completion of this course the participants will be well known for the following items:

·        Identify the various forms of corrosion and the specific mechanisms that result in each form

·        Understand electrochemical processes and concepts

·        Recognize the different types of corrosive environments that affect corrosion

·        Control corrosion by selection of design and engineering materials, modification of environment, cathodic and anodic protection, and protective coatings

·        Monitor corrosion using testing, inspection, specimen exposure, electrochemical methods, water chemistry and analysis of deposits

·        Damage Mechanisms: Overview of corrosion, cracking, mechanical damage, and degradation in equipment.

·        Recognition and Assessment: Guidance on identifying damage signs, assessing severity, and understanding contributing factors.

·        Risk-Based Inspection (RBI): Prioritizing inspections based on risk associated with damage mechanisms.

·        Inspection Techniques: Information on detecting, monitoring, and assessing damage using NDT and visual methods.

·        Mitigation and Management: Recommendations for managing damage, including corrosion control, coatings, repairs, and monitoring.

·        Decision-Making: Assisting in informed decisions about equipment integrity, considering damage evaluation, inspections, and risk assessments.

Who Should Attend?

 This course is designed for engineers, chemists and technicians, other professionals who

would like to expand their knowledge of Corrosion control, monitoring and management.

This course provides specific benefits to:

• Personnel who are responsible for identifying and assessing damage or deterioration in equipment. It is particularly useful for activities such as FFS assessments, RLA, risk-based inspection studies, and similar tasks.
• Inspectors and Examiners in performing effective in-service inspections of pressure vessels, piping, and tanks.
• Engineers, Supervisors, and Managers involved in assessing mechanical integrity or equipment reliability to perform decision-making processes accordingly.
• Process and Plant Designers in understanding the causes of damage mechanisms during material selection and design stages.
• Operations Personnel in gaining insight into the various factors influencing damage mechanisms.
• Personnel who are involved in mitigation and monitoring acquire knowledge of different examination and testing techniques.

     About the lecturer

Course Outline:

Chapter 1 – Overview of Refinery Damage Mechanisms (API 571 Framework)

1.1 Classification of Damage Mechanisms

• Metal loss (general & localized)
• Stress corrosion cracking (SCC)
• Hydrogen damage (HTHA & wet H₂S)
• Metallurgical failures
• Mechanical failures
• Other refinery corrosion forms

1.2 Metal Loss – General & Localized Corrosion

1. Electrochemical & Flow-Related Damage

1. Galvanic corrosion
2. Pitting corrosion
3. Crevice corrosion
4. Intergranular attack
5. Erosion–corrosion

1. Acid & Salt-Related Corrosion

1. Hydrogen chloride (HCl) corrosion
2. Ammonium bisulfide (NH₄HS) corrosion
3. Carbon dioxide (CO₂) corrosion
4. Process chemical corrosion
5. Organic chlorides
6. Aluminum chloride
7. Sulfuric acid (H₂SO₄)
8. Hydrofluoric acid (HF)
9. Phosphoric acid
10. Phenol (carbolic acid)
11. Amine corrosion

1. Environmental & External Damage

1. Atmospheric corrosion
2. Corrosion under insulation (CUI)
3. External corrosion of piping & equipment

1. High-Temperature Metal Loss

1. High-temperature sulfidation (without hydrogen)
2. High-temperature sulfidation (with hydrogen)
3. Naphthenic acid corrosion (NAC)
4. High-temperature oxidation

1.3 Stress Corrosion Cracking (SCC)

1. Environmental SCC

• Chloride SCC (Cl-SCC)
• Alkaline SCC (ASCC)
• Carbonate / carbonic acid SCC
• Polythionic acid SCC (PTA-SCC)
• Ammonia SCC (NH₃-SCC)
• Hydrogen cyanide (HCN) cracking

1. Wet H₂S Cracking Mechanisms

• Hydrogen blistering
• Sulfide stress cracking (SSC)
• Hydrogen-induced cracking (HIC)
• Stress-oriented HIC (SOHIC)

1.4 Hydrogen Damage – High & Low Temperature

• High-Temperature Hydrogen Attack (HTHA)
• Nelson Curves – limitations & misuse
• Early warning signs vs catastrophic failure
• Inspection challenges

1.5 Metallurgical Failures

• Grain growth
• Graphitization
• Hardening & loss of toughness
• Sensitization
• Sigma phase formation
• 885°F (475°C) embrittlement
• Temper embrittlement
• Liquid metal embrittlement
• Carburization
• Metal dusting
• Decarburization

1.6 Mechanical Failures (Corrosion-Related)

• Incorrect or defective materials
• Mechanical fatigue
• Corrosion fatigue
• Cavitation damage
• Mechanical damage
• Overloading & over-pressuring
• Brittle fracture
• Creep & stress rupture
• Thermal shock & thermal fatigue

1.7 Other Refinery Corrosion Forms

• Boiler feedwater corrosion
• Steam condensate corrosion
• Cooling water corrosion
• Fuel ash corrosion

DAYS 2 → END – UNIT-BASED CORROSION

1. Crude & Vacuum Distillation Units (CDU / VDU)

1.1 Purpose & Process

• Fractionation of crude oil into boiling-range products
• Removal of salts, water, and inorganic contaminants
• Atmospheric and vacuum distillation overview
• Key equipment: desalter, columns, overhead systems, heaters

1.2 Probable Damage Mechanisms

• HCl corrosion in overhead systems
• Ammonium chloride salt deposition
• CO₂ corrosion
• Naphthenic acid corrosion (NAC)
• High-temperature sulfidation
• Erosion–corrosion
• Corrosion under insulation (CUI)

1.3 Materials Selection

• Carbon steel for towers and piping
• Low-alloy steels for high-temperature services
• Stainless steels for overhead condensers and piping
• Use of cladding and corrosion allowance

1.4 Inspection Methods & Corrosion Monitoring

• UT thickness monitoring for thinning
• Radiography for overhead corrosion
• Corrosion coupons and electrical resistance probes
• pH, chloride, and iron monitoring in overhead water
• Visual inspection of desalter internals

1.5 Corrosion Tricks & Notes

• Desalter efficiency directly controls corrosion severity
• Poor water wash causes under-deposit corrosion
• Over-neutralization increases fouling and corrosion
• Dead legs in overhead systems are high-risk zones

2. Fluid Catalytic Cracking Unit (FCC)

2.1 Purpose & Process

• Conversion of heavy fractions into lighter products
• Reactor–regenerator system operation
• Catalyst circulation and regeneration

2.2 Probable Damage Mechanisms

• High-temperature sulfidation
• High-temperature oxidation
• Polythionic acid SCC (PTA-SCC)
• Catalyst erosion
• Refractory degradation

2.3 Materials Selection

• Carbon steel for low-temperature sections
• Cr-Mo steels for hot services
• Stainless steels for cracking-resistant applications
• Refractory-lined equipment

2.4 Inspection Methods & Corrosion Monitoring

• Visual inspection of refractory and erosion zones
• UT for sulfidation thinning
• Profile radiography for elbows and bends
• Shutdown inspection for PTA-SCC
• Thickness trending in slurry circuits

2.5 Corrosion Tricks & Notes

• PTA-SCC risk peaks during shutdown
• Oxygen ingress is a major corrosion trigger
• Erosion often masks corrosion damage
• Catalyst fines cause localized metal loss

3. Cracked Light Ends Recovery Unit (CLER)

3.1 Purpose & Process

• Separation and recovery of cracked light hydrocarbons
• Compression, cooling, and fractionation

3.2 Probable Damage Mechanisms

• Wet H₂S corrosion
• Hydrogen-induced cracking (HIC)
• Carbonate and alkaline SCC
• Ammonium salt deposition

3.3 Materials Selection

• Carbon steel for general services
• Low-alloy steels for hydrogen-containing systems
• Controlled use of stainless steels

3.4 Inspection Methods & Corrosion Monitoring

• UT and shear-wave UT for cracking
• Wet H₂S cracking inspection per NACE MR0175
• Corrosion coupons in water-rich zones
• Process monitoring of water and H₂S content

3.5 Corrosion Tricks & Notes

• Cracks initiate at weld HAZ
• Condensation zones are most aggressive
• Hydrogen partial pressure often underestimated

4. HF Alkylation Unit

4.1 Purpose & Process

• Alkylation of olefins using hydrofluoric acid
• Production of high-octane alkylate

4.2 Probable Damage Mechanisms

• HF acid corrosion
• Hydrogen blistering
• Hydrogen embrittlement
• Localized corrosion at injection points

4.3 Materials Selection

• Carbon steel with strict velocity limits
• Specialized alloys for severe HF exposure
• Linings and protective coatings

4.4 Inspection Methods & Corrosion Monitoring

• UT with frequent thickness mapping
• HF corrosion probes
• Visual inspection with HF safety protocols
• Acid strength and water content monitoring

4.5 Corrosion Tricks & Notes

• Water contamination drastically increases corrosion
• Injection points fail first
• Inspection access is often limited by safety constraints

5. Sulfuric Acid Alkylation Unit

5.1 Purpose & Process

• Alkylation using sulfuric acid catalyst
• Acid circulation and regeneration

5.2 Probable Damage Mechanisms

• Sulfuric acid corrosion
• Hydrogen grooving
• Under-deposit corrosion
• Atmospheric corrosion during shutdown

5.3 Materials Selection

• Carbon steel within controlled acid concentration
• Alloy upgrades for severe services

5.4 Inspection Methods & Corrosion Monitoring

• UT thickness monitoring
• Visual inspection during shutdown
• Acid concentration and temperature tracking
• Coupon monitoring in acid circuits

5.5 Corrosion Tricks & Notes

• Acid dilution during upset conditions accelerates corrosion
• Shutdown exposure causes rapid metal loss
• Acid carryover damages downstream units

6. Hydroprocessing Units (Hydrotreating / Hydrocracking)

6.1 Purpose & Process

• Removal of sulfur, nitrogen, and contaminants
• Hydrogenation under high pressure and temperature

6.2 Probable Damage Mechanisms

• High-temperature hydrogen attack (HTHA)
• High-temperature sulfidation
• Ammonium bisulfide corrosion
• Wet H₂S cracking
• PTA-SCC

6.3 Materials Selection

• Cr-Mo steels for reactors and hot piping
• Stainless steel overlays and cladding
• Controlled metallurgy for weldments

6.4 Inspection Methods & Corrosion Monitoring

• Advanced UT for HTHA (TOFD, PAUT)
• High-risk location mapping per API 941
• NH₄HS velocity monitoring
• Corrosion coupons and iron analysis

6.5 Corrosion Tricks & Notes

• Nelson curves are guidance, not guarantees
• NH₄HS corrosion accelerates with velocity
• Hydrogen damage often invisible until advanced

7. Catalytic Reforming Unit

7.1 Purpose & Process

• Production of high-octane reformate
• Hydrogen generation

7.2 Probable Damage Mechanisms

• High-temperature hydrogen damage
• Stress corrosion cracking
• Metal dusting (localized)

7.3 Materials Selection

• Cr-Mo steels for hot hydrogen services
• Stainless steels in cooler sections

7.4 Inspection Methods & Corrosion Monitoring

• UT for high-temperature thinning
• Metallurgical replication
• Hydrogen partial pressure monitoring
• Inspection during turnaround

7.5 Corrosion Tricks & Notes

• Startup/shutdown causes most damage
• Hydrogen purity affects corrosion severity
• Localized metal dusting often overlooked

8. Delayed Coking Unit (DCU)

8.1 Purpose & Process

• Thermal cracking of residual feeds
• Coke drum switching operations

8.2 Probable Damage Mechanisms

• Severe thermal fatigue
• Naphthenic acid corrosion
• High-temperature sulfidation
• Erosion–corrosion

8.3 Materials Selection

• Low-alloy steels for hot piping
• Specialized alloys for coke drums

8.4 Inspection Methods & Corrosion Monitoring

• UT thickness mapping
• Acoustic emission for crack detection
• Visual inspection during decoking
• Temperature cycling analysis

8.5 Corrosion Tricks & Notes

• Drum switching causes thermal shock
• Cracks initiate at weld toes
• Geometry limits inspection effectiveness

9. Amine Treating Units

9.1 Purpose & Process

• Removal of H₂S and CO₂ from streams
• Amine circulation and regeneration

9.2 Probable Damage Mechanisms

• Amine corrosion
• Heat-stable salt corrosion
• Acid gas flashing
• Wet H₂S cracking

9.3 Materials Selection

• Carbon steel for most services
• Stainless steels in high-risk zones

9.4 Inspection Methods & Corrosion Monitoring

• Corrosion coupons and probes
• Iron content and HSS analysis
• UT of reboilers and lean amine piping
• Visual inspection of contactors

9.5 Corrosion Tricks & Notes

• High lean amine temperature accelerates corrosion
• Poor filtration hides corrosion indicators
• Sampling point location is critical

10. Sulfur Recovery Unit (SRU)

10.1 Purpose & Process

• Conversion of H₂S to elemental sulfur
• Claus process and sulfur handling systems

10.2 Probable Damage Mechanisms

• High-temperature sulfidation and oxidation
• Sulfur corrosion during shutdown
• Acid dew-point corrosion
• Ammonium salt corrosion
• Thermal fatigue

10.3 Materials Selection

• Carbon steel for sulfur services
• Cr-Mo steels for hot sections
• Stainless steels in condensers
• Refractory linings

10.4 Inspection Methods & Corrosion Monitoring

• UT and visual inspection of hot piping
• Refractory inspection and thickness checks
• Corrosion monitoring in sulfur rundown lines
• Oxygen ingress monitoring

10.5 Corrosion Tricks & Notes

• Shutdown corrosion is more severe than operation
• Oxygen ingress is the main corrosion accelerator
• Low points and dead legs are failure-prone

Course Methodology 

A variety of methodologies will be used during the course that includes:

• (30%) Based on Case Studies
• (30%) Techniques
• (30%) Role Play
• (10%) Concepts
• Pre-test and Post-test
• Variety of Learning Methods
• Lectures
• Case Studies and Self Questionaires
• Group Work
• Discussion
• Presentation