When Chemistry Eats Steel

A Metallurgist’s Guide to Heat Exchanger Failures in the Chemical & Petrochemical Industry

In more than four decades of looking down a microscope at why industrial equipment fails, I have come to regard the heat exchanger as the most under-appreciated component in any process plant. It rarely makes the front page when a unit trips. It carries neither the glamour of a reactor nor the visibility of a compressor. And yet, across the 500-plus heat exchanger investigations my teams and I have closed for the chemical and petrochemical industry, one truth keeps repeating itself: when a heat exchanger fails, it does not just leak — it takes the plant’s economics, safety case, and production schedule down with it.

This is the first in a three-part series. Here we deal with the chemical and petrochemical exchanger. Part 2 will address condensers, and Part 3 will take on high-temperature refinery service. My aim across all three is simple — to show how a disciplined metallurgical investigation converts a tube leak into a root cause, and a root cause into a decision that keeps the plant running.

Why the Heat Exchanger Deserves More Respect

A heat exchanger is, in the truest sense, the heart of a process unit. As long as it is online, the plant breathes — production continues, throughput holds, and the unit stays in balance. The moment it is down, everything downstream of it begins to choke.

But there is a second, quieter contribution that decides whether a plant is profitable or merely operational: the efficiency of heat transfer. Every degree of heat recovered in a feed-effluent exchanger is a degree that does not have to be purchased in a fired heater. A fouled, under-performing exchanger silently taxes the plant on every tonne of product. So the exchanger carries a dual burden — it must stay online, and it must stay efficient. A failure attacks both at once.

This is why the consequence of a heat exchanger failure is rarely proportional to the size of the leaking tube. A single perforated tube, the diameter of a thumb, can force an unplanned shutdown of a unit worth crores per day.

The Anatomy of the Problem: Where Heat Exchangers Are Damaged

The chemical and petrochemical industry runs an enormous variety of exchangers — shell-and-tube, U-tube, kettle reboilers, air-fin coolers, plate exchangers — and the geometry chosen depends entirely on whether heat is being recovered from a stream or supplied to a process. But regardless of type, the investigator must understand that damage does not occur in one place. It occurs across at least five distinct zones, and each tells a different part of the story.

The tubes (1). This is the insight that separates an experienced exchanger investigator from a generalist: heat exchanger tubes are specified with no corrosion allowance. A pressure-vessel shell may carry 3 mm of sacrificial thickness; a tube wall of 1.6–2.1 mm carries none. Every micron of metal loss is a micron closer to perforation. This is why the tube is almost always where the failure announces itself.

The tubesheet (2). Where tubes terminate and the shell-side and tube-side fluids are kept apart. Galvanic couples, crevice corrosion, and deposit accumulation make this a recurring site of trouble.

The tube-to-tubesheet joint (3). Rolled, welded, or both. A joint that relaxes, cracks, or corrodes preferentially becomes a direct leak path between two fluids that were never meant to meet.

The baffles and support plates (4). They direct shell-side flow — and in doing so, they create the high-velocity zones, impingement points, and stagnant pockets where erosion-corrosion and under-deposit attack begin.

The shell and welds (5). The shell itself, its longitudinal and circumferential seams, and the nozzle welds. Weld zones, with their altered microstructure and residual stress, are preferential sites for cracking.

The Damage Mechanisms That Dominate Chemical & Petrochemical Service

Across my investigations, the failures in this sector cluster into a recognizable set of mechanisms. The table below is the working map my teams use.

#	Damage Mechanism	Typical Location	Visual Signature	Common Driver
1	Under-deposit / Pitting corrosion	Tube ID/OD, shell bottom	Localized pits beneath scale / deposit	Stagnant flow, chloride concentration under deposits
2	Chloride Stress-Corrosion Cracking	Austenitic SS tubes, U-bends	Branched, multi-directional cracks	Chlorides + tensile stress + temperature on 300-series SS
3	Erosion-corrosion	Tube inlets, baffle windows, bends	Horseshoe grooves, smooth wastage	High velocity, turbulence, two-phase flow
4	Dezincification / Dealloying	Brass and copper-alloy tubes	Reddish copper-rich plug, porous layer	Selective leaching of zinc in aggressive water
5	Corrosion fatigue	Tubes near baffles, U-bends	Transverse cracking, beach marks	Cyclic stress (vibration/thermal) + corrosive medium
6	Galvanic corrosion	Tube-to-tubesheet, dissimilar joints	Preferential attack of less-noble metal	Dissimilar metals in a conductive electrolyte
7	Microbiologically Influenced Corrosion	Cooling-water side, stagnant legs	Discrete hemispherical pits, tubercles	Biofilm, idle periods, untreated water
8	Flow-Induced Vibration	Tubes at baffle edges, inlet rows	Fretting, thinning, fatigue at supports	Shell-side velocity exciting tube natural frequency

The temptation — and I see it constantly in reports from less rigorous laboratories — is to name the mechanism from a visual inspection alone. A pit is called “pitting,” a crack is called “SCC,” and the report is closed. This is not failure analysis. It is guessing with vocabulary.

The TCR Approach: Why One Technique Is Never Enough

A heat exchanger failure is a system failure. The mechanical design, the fabrication history, and the metallurgy all conspire to produce the damage you finally see. To untangle them, no single technique suffices. The correct diagnosis emerges only when visual examination, electron microscopy, metallography, and EDS analysis are made to converge on the same conclusion.

Step	Technique	What it establishes
1	Visual & dimensional examination	As-received condition, side of attack (ID/OD), damage distribution, wall-thickness mapping, deposit sampling
2	Stereo-microscopy	Morphology at low magnification — localized vs general, branched vs single cracking, beach marks
3	Scanning Electron Microscopy (SEM)	Character of damage — transgranular vs intergranular, fatigue striations, pit sub-structure
4	Energy Dispersive Spectroscopy (EDS)	Chemistry of deposit, corrosion product and pit base — chlorine, sulphur as decisive evidence
5	Metallography (cross-section)	Crack path vs grain structure, depth of attack, dealloyed layers, sensitization, microstructure correctness
6	Mechanical & chemical tests	Hardness traverse, tube chemistry vs specification, replication — exonerate or implicate the material

The discipline is this: when the SEM morphology, the EDS chemistry, the metallographic cross-section, and the service history all point to the same mechanism, the conclusion is no longer an opinion. It is proven. When they disagree, you have not finished the investigation.

The Real Lesson: Damage Is a Symptom, Not the Disease

In a great many of the chemical-industry exchangers I have examined, the tube failure was the last event in a chain, not the first. Under-deposit pitting is a symptom of a flow or water-treatment problem. Chloride SCC is a symptom of a material selection that did not respect the service environment. Flow-induced vibration is a symptom of a mechanical design margin that was too thin from day one.

This is why a credible failure report cannot end at “the tube failed by chloride stress-corrosion cracking.” It must go on to answer: why were chlorides present, why was the stress sufficient, and why was a susceptible material in that service to begin with? Only then does the report give the plant something it can act on — a change in water chemistry, a change in metallurgy, a change in operating window — rather than a like-for-like replacement that will fail again on the same schedule.

The Exchanger Will Tell You Everything — If You Know How to Listen

A failed heat exchanger tube is not a piece of scrap. It is a complete, contemporaneous record of everything the plant did to it — the chemistry it saw, the velocities it endured, the temperatures it cycled through, and the decisions made years earlier at the design and material-selection stage. The metallurgist’s job is to read that record correctly, and the only way to read it correctly is to make several independent techniques agree before signing the conclusion.

After 1,500-plus of these investigations, I remain convinced that most heat exchanger failures in our industry are preventable — not by better steel, but by better understanding of the steel we already use in the service we already run.

Coming next in this series

• Part 2 — Condenser Failures: ammonia grooving, inlet-end erosion-corrosion, and the microbiological attack that hides during idle periods.

• Part 3 — Refinery & High-Temperature Exchangers: polythionic acid SCC, sulphidation, and flow-accelerated corrosion.

About TCR Advanced Engineering

TCR Advanced Engineering is a NABL / ISO 17025-accredited materials testing and asset-integrity firm based in Vadodara, with over 9,000 investigations completed across 18 industries. If a heat exchanger failure is keeping your unit offline, our metallurgical and NDT teams can help you find the root cause — not just the leak.

Talk to our failure analysis team:  testing@tcradvanced.com  ·  +91 8511179948 (24-hour hotline)

FAQs

1. What are the most common heat exchanger failure mechanisms in chemical plants?

The most common mechanisms include under-deposit corrosion, chloride stress corrosion cracking, erosion-corrosion, flow-induced vibration, microbiologically influenced corrosion, and corrosion fatigue. These failures usually result from a combination of operating conditions, material selection, and water chemistry issues.

2. Why do heat exchanger tubes fail more frequently than other components?

Heat exchanger tubes are thin-walled and typically designed without corrosion allowance. Even minor metal loss due to corrosion, erosion, or pitting can quickly lead to perforation and leakage, making them the most vulnerable part of the system.

3. What is under-deposit corrosion in heat exchangers?

Under-deposit corrosion occurs when deposits such as scale, sludge, or biofilms accumulate on tube surfaces, trapping corrosive agents like chlorides underneath. This creates localized attack that leads to pitting and eventual tube failure.

4. How does chloride stress corrosion cracking occur in heat exchangers?

Chloride stress corrosion cracking occurs when stainless steel is exposed to a combination of tensile stress, elevated temperature, and chloride-rich environments. It leads to branched cracking, often without significant general corrosion.

5. What role does flow-induced vibration play in tube failure?

Flow-induced vibration happens when shell-side fluid velocity excites tube natural frequencies. This leads to tube-to-baffle contact, fretting, fatigue cracking, and eventual leakage, especially near support plates and inlet regions.

6. How is erosion-corrosion different from normal corrosion?

Erosion-corrosion is a combined mechanism where high-velocity fluid flow mechanically removes protective oxide layers, accelerating corrosion. It typically appears as smooth, horseshoe-shaped wastage in high-turbulence areas.

7. Can microbiologically influenced corrosion damage heat exchangers?

Yes, MIC occurs when bacteria form biofilms on internal surfaces, creating localized corrosive environments. It results in tubercle formation and deep pitting, especially in stagnant or poorly treated cooling water systems.

8. Why is tube-to-tubesheet joint failure critical in heat exchangers?

The tube-to-tubesheet joint separates shell-side and tube-side fluids. Any degradation such as cracking, crevice corrosion, or loosening can directly cause cross-contamination and system leakage.

9. How do metallurgical investigations identify the exact failure cause?

Investigations combine visual inspection, SEM analysis, EDS chemical detection, metallography, and mechanical testing. Correlating all results helps confirm whether failure is due to corrosion, fatigue, or combined mechanisms.

10. Can heat exchanger failures be prevented completely?

While complete elimination is difficult, most failures can be significantly reduced through proper material selection, controlled operating conditions, effective water treatment, and regular condition monitoring and inspection programs.