Case Studies

Coating Deterioration Assessment of a High-Rise Steel Structure in Baku Background In 2013, XXXX, a prominent construction company, was awarded the contract for the prestigious steel structure project in Baku, Azerbaijan. The structural steel painting contract was awarded to a contractor based in the UAE, who commenced painting in March 2014 and completed the installation by July 2014. However, approximately four years after the project’s completion, significant coating deterioration was observed, including cracking and delamination of the paint on the steel structure. XXXX approached Colossal Consultants in December 2020 to conduct a detailed investigation to determine the root cause of the coating deterioration and provide recommendations for remediation. Scope of Work Colossal Consultants proposed a comprehensive scope of work to investigate the coating deterioration, which included: Document Review: Examination of painting procedures, paint application reports, and technical specifications. Site Testing: Visual examination of the coating condition. Coating thickness verification using random sampling. Adhesion testing on existing coatings. Salt contamination testing. Determination of the corrosivity category for the Baku region. Laboratory Testing: Salt spray and condensation tests on panels prepared by the paint manufacturer. Fourier-transform infrared spectroscopy (FTIR) analysis of coating samples to evaluate chemical composition. Findings Document Review The painting system used for the project consisted of: Primer: Hempadur Zinc 17360 (40 microns) Intermediate Coat: Hempadur Fast Dry 17410 (70 microns) Finish Coat: Hempathane HS 55610 (50 microns) The total dry film thickness (DFT) was specified at 160 microns, designed for a C3 Corrosivity High Durability environment as per ISO 12944. However, the contractor failed to provide detailed inspection reports for each stage of the coating process, raising concerns about the quality control during application. Site Testing Visual Examination: Extensive cracking and peeling of the coating were observed, particularly at sharp edges and corners of the structural steel. The design of the structure lacked proper drainage, leading to water accumulation in certain areas, which exacerbated the coating deterioration. Coating Thickness (DFT) Verification: The average DFT was found to be 238 microns in March 2021, exceeding the specified 160 microns. While higher DFT can provide better protection, excessive thickness can lead to internal stresses and cracking, especially at sharp edges. Adhesion Testing: The adhesion values were satisfactory, with an average of 8 MPa. However, the high adhesion values near cracked areas indicated a lack of flexibility in the coating, contributing to the cracking. Salt Contamination Test: The maximum salt contamination value recorded was 2.7 µg/cm², well below the acceptable limit of 5 µg/cm² as per ISO/TR 15235. This ruled out salt contamination as a contributing factor to the coating failure. Corrosivity Category for Baku: Based on ISO 9223, the corrosivity category for Baku was determined to be C3, which aligns with the paint system’s design specifications. Laboratory Testing Salt Spray and Condensation Tests: The paint system was tested in the laboratory and found to comply with the C3 High Durability requirements as per ISO 12944. The panels showed no signs of blistering, chalking, or discoloration after 480 hours of salt spray testing and 240 hours of condensation testing. FTIR Analysis: The FTIR analysis revealed that the primer and intermediate coats had lower epoxy content than expected, indicating improper mixing of the base and hardener. This improper mixing led to a lack of flexibility in the coating, resulting in cracking and delamination. Conclusions The coating deterioration was primarily attributed to improper application by the contractor, specifically: Incorrect Mixing Ratio: The primer and intermediate coats had lower epoxy content than specified, leading to a lack of flexibility and increased internal stresses within the coating system. Sharp Edges and Poor Drainage: The structural design did not account for proper drainage, leading to water accumulation. Additionally, sharp edges were not rounded off, creating stress points that contributed to coating failure. Lack of Documentation: The contractor failed to provide detailed inspection reports, raising doubts about the quality control during the painting process. The corrosion problem was not due to external environmental factors but rather the result of negligence during the application process. Recommendations Coating Rehabilitation: All areas showing coating deterioration should be rehabilitated. Proper surface preparation, correct mixing ratios, and adherence to application procedures must be ensured. Rounding Off Sharp Edges: Sharp edges on the structural steel should be rounded off to prevent stress concentration and subsequent coating failure. Drainage Improvements: Drainage holes should be added to prevent water accumulation, which can lead to localized coating holidays and microbiological activity. Quality Control: Future projects should include rigorous quality control measures, including detailed documentation of each stage of the coating process.

Root Cause Analysis of Heat Exchanger Tube Failures Introduction Colossal Consultants was commissioned by an Egypt based Oil Refining Company to investigate recurring tube failures in one of the Heat Exchangers within the Naphtha Hydrotreater Unit. The exchanger, critical to reactor effluent cooling, experienced multiple leaks in March and April 2021, leading to unplanned shutdowns and operational losses. This case study outlines the root cause analysis (RCA), findings, and recommendations provided by Colossal Consultants to mitigate future failures. Background Equipment & Process Context: Heat Exchanger: Reactor effluent/stripper feed exchanger with 438 tubes (ASTM A179 low-carbon steel). Process Stream: Hydrotreater reactor effluent containing hydrogen, naphtha, and corrosive salts (ammonium chloride, NH₄Cl, and ammonium bisulfide, NH₄HS). Failure History: March 2021: 15 tubes leaked after restart post-maintenance. April 2021: 21 tubes failed, requiring extended shutdown. Design Safeguards: Intermittent wash water injection to dissolve salt deposits. Material specification compliant with ASTM A179. Methodology Colossal Consultants conducted a multi-disciplinary investigation: Mechanical & Metallurgical Analysis Visual Inspection: Identified uniform wall thinning, bulging, and perforations near tube sheets (Photographs 7–14). Destructive Testing: Tensile strength, hardness (HV 92), and chemical composition (C: 0.11%, Mn: 0.38%) complied with ASTM A179. Flattening/flaring tests confirmed ductility. Microstructural Analysis: Ferrite-dominated structure with minimal pearlite (Photographs 15–17). SEM/EDS & XRD: Corrosive deposits (Fe₃O₄, FeS₂, CaCO₃) with chloride, sulfur, and oxygen traces (Photographs 19–21). Process & Corrosion Analysis API RP 932B Assessment: Predicted NH₄Cl deposition temperature (94°C) exceeded operating temperatures (64–79°C), leading to salt accumulation. pH & Chloride Analysis: Separator sour water pH dropped to 4.8 with 676 ppm chlorides, indicating acidic HCl corrosion. Corrosion Rate Estimation (API RP 581): 13–21 mpy general corrosion due to low pH (~4) and stagnant wash water. Operational Review Intermittent wash water injection (1–1.4% of feed rate) failed to flush salts. Tube-side pressure (20.87 kg/cm²) exceeded shell-side pressure, exacerbating bulging in thinned regions. Key Findings Primary Failure Mechanism: Hydrochloric Acid Corrosion: Chloride-rich, low-pH environment caused uniform thinning and perforation. Contributing Factors: Intermittent wash water injection led to NH₄Cl deposition. High tube-side pressure (vs. shell-side) accelerated bulging. Secondary Factors: Trace sulfur (EDS) indicated minor NH₄HS contribution. Material compliance ruled out metallurgical defects. Recommendations by Colossal Consultants Process Modifications: Continuous Wash Water Injection: Increase injection rate to 3% of feed volume (vs. 1.4%) at all three locations. Enhance Monitoring: Real-time pH/chloride sensors in critical exchangers. Mechanical Upgrades: Material Upgrade: Replace tubes with duplex stainless steel (e.g., UNS S32205) for chloride resistance. Design Review: Optimize tube velocity and pressure differentials to prevent bulging. Operational Best Practices: Strict moisture control in naphtha feed tanks. Monthly corrosion audits using in-situ replica metallography. Conclusion Colossal Consultants identified hydrochloric acid corrosion due to inadequate wash water injection as the root cause of heat exchanger tube failures. By implementing continuous wash water systems, upgrading materials, and enhancing monitoring protocols, ASORC eliminated recurring leaks and extended exchanger lifespan by 40%. This case underscores the importance of holistic RCA combining metallurgical, process, and operational insights to ensure asset integrity in corrosive environments.

Hydrogen Induced Cracking in Boiler Water Drum Manway Neck Weld Introduction This case study examines the root cause analysis of a cracking incident in the manway neck weld of a boiler water drum at a Sugar Refinery in Malaysia. The incident, which resulted in leakage and plant downtime, highlights the potential dangers of inadequately controlled welding processes, material selection, and handling of welding consumables. Background Fabrication: XXXX was contracted to fabricate two boiler water drums for Sugar Refinery. Initial Cracks (2019): After 13 months of service, cracks were discovered in Boiler 2’s water drum. These were characterized as linear, gouged, repaired, and the boiler returned to service. Leakage (2021): On March 30th, 2021, a leak was discovered at the rear manway neck of Boiler 2. This forced a plant shutdown. Investigation Trigger: The client and XXXX engaged Colossal Consultants to conduct a root cause analysis (RCA) for submission to local regulatory bodies as part of resuming boiler operation. Investigation Methodology The RCA was conducted using the Fishbone Diagram method, as per BS EN 62740:2015. This involved analyzing factors across various categories: Environment: Welding conditions, joint configuration, etc. Materials: Chemical composition (CEV), microstructural abnormalities, hardness, etc. Manpower: Training, competency, awareness of failure modes, etc. Methods: Preheating and PWHT, welding heat input, etc. Machines: Calibrated welding equipment. Measurements: Hardness checks, NDT timing, etc. The investigation included: Document review of relevant quality control records. Visual examination of the failed section Dye penetration test and ultrasonic testing Sectioning, Tensile test, Chemical analysis, Microscopic examination, Charpy Impact test SEM/EDS Analysis. Key Findings The investigation revealed several critical issues that contributed to the cracking: Low Heat Input: The welding procedure used a low heat input (0.2-0.4 KJ/mm), potentially leading to faster cooling rates. Absence of Preheat: Preheat was not specified for nozzle thickness over 30mm, which also increases cooling rate due to heat sinking by the nozzle. High Carbon Equivalent (CEV): The manway neck material had a high CEV of 0.44, increasing the steel’s hardenability. Though this value might be within the limits of BS 1501 part 1 1980, The associated risks should have been addressed. Tempered Martensite: Microstructural analysis revealed the presence of tempered martensite at the crack origin, indicating a hardened and brittle microstructure. High Hardness: Hardness measurements in the heat-affected zone (HAZ) were higher than expected even in the stress-relieved state suggesting incomplete relief of residual stresses. Highly Restrained Weld Joint: The manway to dished head weld joint was identified as a highly restrained joint, increasing residual stress. Lack of Controls for FCAW Wires: The welding consumable storage procedure did not adequately address the control of FCAW (Flux-Cored Arc Welding) wires. These wires, like SMAW electrodes, are hygroscopic and can absorb moisture. Brittle Fracture: The fracture surfaces showed evidence of transgranular, brittle cracking, consistent with Hydrogen Induced Cracking. Hydrogen Source: It was concluded that the moisture in welding wires, along with other potential factors like contamination of base material and welding consumables can lead to Hydrogen Induced Cracking. Location of Cracks: The cracks were predominantly located at the weld toes indicating under-bead cracking which is also a manifestation of Hydrogen Induced Cracking. Impact Test: The weld metal was noted to be relatively brittle when compared to the parent materials with very little or no evidence of ductile feature. Root Cause Based on these findings, the root cause of the failure was determined to be Hydrogen Induced Cracking (HIC). This was facilitated by a combination of: A high CEV base material that promoted hardened structures. Fast cooling rates due to the low heat input and absence of preheating Restrained weld joint design that led to high residual stresses. The presence of hydrogen from moisture and possible contamination in the welding consumables. Lack of controls in material procurement, selection and consumables storage. Recommendations To prevent future occurrences, the following recommendations were made: Material Procurement: Procure base materials with a CEV no greater than 0.42. Preheat: Diligently apply preheat to heavy wall sections to reduce the cooling rate. Consumable Control: Improve storage and handling practices for welding consumables, particularly FCAW wires, with reference to manufacturer storage recommendations. Hydrogen Management: Employ welding consumables with lower diffusible hydrogen content or a dehydrogenation heat treatment to remove hydrogen after welding, particularly with high CEV/thickness combination. Training and Awareness: Provide training to all construction and quality personnel on HIC. Baseline Survey: Conduct a comprehensive baseline survey for integrity management of the vessel. NDT Examination: Improve the timing and execution of non-destructive testing before and after PWHT. Dehydrogenation HT: Use dehydrogenation heat treatment to drive out hydrogen from weldment after welding when high CEV materials are used. Conclusion This case study emphasizes the importance of stringent controls over welding parameters, material selection, and consumable management when fabricating pressure vessels. The failure was a result of the perfect storm of inadequate welding procedures, material susceptibility, and improper handling of consumables, which made the weldment susceptible to HIC. It is crucial for fabrication and quality control teams to be aware of failure mechanisms like HIC and to implement preventive measures to ensure the structural integrity and longevity of critical equipment. The lessons from this incident should serve as a reminder of the need for vigilance in all phases of fabrication to prevent similar failures.

Corrosion Under Insulation (CUI) at a Dubai Hotel Swimming Pool Introduction This case study examines a severe corrosion incident in a chilled water system at a hotel in Dubai. The system, serving air handling units (AHUs) and swimming pools, experienced significant external corrosion within three years of installation. This case underscores the critical importance of proper design, material selection, installation, and maintenance in preventing Corrosion Under Insulation (CUI). The study includes detailed technical specifications and testing results. Background System:Chilled water application system. Operating Conditions: Pressure: < 10 bars (145.0 psi) Temperature: 65 to 80 °C (149.0 to 176.0 °F) Materials: Piping:2-inch (5.1 cm) Schedule 40 Grade B ERW black steel pipe per ASTM A53. Internal Coating:Specified epoxy coating (application inadequately met). External Coating System (Specified): First Layer: Epicon Zinc Rich Primer B-2 + thinner (or equivalent), 75 microns (3.0 mils) DFT. Second Layer: Epicon HB-CL + thinner (or equivalent), 50 microns (2.0 mils) DFT. Third Layer: UNY Marine 100 + thinner (or equivalent), 50 microns (2.0 mils) DFT. Insulation:Closed-cell nitrile butadiene rubber (NBR) elastomeric foam. Field Insulation:Specified to meet “Sheet Metal Ducts Thermal Insulation Wrap Commercial/Residential Duct Systems” requirements per UAE jurisdiction (reference to Section 15082 was made). History:System in operation for almost two years under a maintenance contract before handover. First leak reported August 2019; multiple leaks led to closure in March 2020. Problem Description Significant external corrosion was observed. Visual inspection revealed: Extensive corrosion evident at joint locations, characterized by rough, pitted surfaces with loose, flaky scale. Severe corrosion at tube-to-coupler joints and elbows. External Coating Thickness:Actual thicknesses of 106-152 microns (4.2-6.0 mils) at “normal” locations, falling below project specification requirements (which called for a combined 175 microns). Minimal internal corrosion, but significant crevice corrosion on the coupler threads. Evidence of external insulation failure (as seen in Figure 1 of the article), which allowed moisture ingress. Investigation & Testing Methods A corrosion specialist conducted a site visit and performed the following tests: Visual Inspection:Documentation of corrosion’s extent and characteristics. Coating Thickness Measurement:Non-destructive measurements using a gauge to determine coating thickness. Chemical Analysis (OES):Optical Emission Spectroscopy using ASTM E415-17: Confirmed pipe material conformed to ASTM A53 Grade B requirements. Tensile Testing (ASTM A370-17a):Conducted to evaluate mechanical properties: Yield Strength, Tensile Strength, and Elongation met requirements of ASTM A53 Grade B (except for elongation which was not considered critical in the study). Hardness Testing (ASTM E92-17):Vickers Hardness Test. Hardness values ranged from 146 to 152 HV10 (with 10 kg load). Microstructure Analysis (ASTM E3-11/E407-07): Uniform distribution of ferrite and pearlite observed (as shown in Figure 4 of the article). X-Ray Diffraction (XRD):Identified constituents of corrosion scale: Magnetite (41.6%) Goethite (24.5%) Hematite (20.6%) Chalcopyrite (5.4%) Lepidocrocite (6.3%) Quartz (1.6%) Water Analysis (APHA 23rd Ed. Methods): pH: 8.40 Total Dissolved Solids (TDS): 205.00 mg/L Electrical Conductivity: 354.14 µS/cm Chlorides (as Cl): 85.880 mg/L Sulphide: 0.02 mg/L Iron (Fe): 2.28 mg/L Dissolved Oxygen: 7.1 mg/L No signs of microbiological activity detected. Findings & Technical Analysis Corrosion Mechanism:Primary corrosion mechanism identified as CUI. Coating Failure:Inconsistent and inadequate coating application resulted in under-protection of base metal. Moisture Ingress:Failure of the insulation and vapor barrier allowed moisture to reach the pipe surface. Crevice Corrosion:The design of the threaded pipe couplers allowed moisture to accumulate, exacerbating crevice corrosion. Water Chemistry:Although slightly alkaline, the water chemistry did not indicate any aggressive components that would significantly contribute to the corrosion of the materials used; therefore, it was determined that water exposure due to insulation failure was the primary issue. Lessons Learned & Mitigation Strategies Coating Application: Implement strict quality control during coating application. Ensure consistent coating application in accordance with specification. Pay close attention to coating thickness, particularly at joints and irregular surfaces. Insulation System Design: Use a multi-layered insulation approach with an effective vapor barrier Design the insulation system to shed water effectively. Pay specific attention to joints and terminations. Material Selection: Consider selecting insulating materials that have low water absorption rates, and quick water evaporation rates. Use corrosion-resistant coatings such as flame-sprayed aluminium when applicable. Select insulation containing corrosion inhibitors. Maintenance: Implement regular inspections of insulation and protective coatings. Replace damaged or degraded insulation promptly. Address any signs of leaks or moisture intrusion immediately. Design Considerations: Minimize crevices and other water-trapping areas. Use appropriate pipe supports and hangers to ensure water can’t pool. Consider using open-cell insulation when appropriate. Conclusion This case study emphasizes the importance of a comprehensive approach to preventing CUI. This approach should include: Proper coating application. Careful insulation selection, design, and installation. Regular inspections and maintenance, including immediate response to issues. The technical data obtained in this investigation provides a detailed example of the corrosion mechanism, and helps engineers understand the complexities and risks associated with CUI. By taking the lessons learned from this event, future corrosion incidents can be mitigated, reducing costs, increasing system reliability, and ensuring the long-term integrity of insulated systems.