A heat exchanger does not fail suddenly. It fails progressively — through fouling that reduces thermal efficiency and accelerates under-deposit corrosion, through tube wall thinning that advances undetected between inspection intervals, through tube-to-tubesheet joint degradation that begins as a weep and ends as a process stream cross-contamination event. The failure is predictable. The failure is preventable. The failure occurs because the maintenance programme was designed around a calendar, not around a condition.
The heat transfer equipment family in industrial service is not a single asset class. Shell and tube heat exchangers, lube oil coolers, steam condensers, and superheaters each operate under different process conditions, accumulate damage through different mechanisms, and require different inspection strategies. A programme that treats them identically will fail to detect the dominant failure mode in each type — and will accumulate latent damage that eventually presents as an unplanned event.
Programme Failure Pattern
The most common heat exchanger maintenance programme in industrial service is a fixed-interval bundle pull, visual inspection, hydroblast cleaning, and return to service. No tube thickness measurement. No eddy current survey. No tube-to-tubesheet joint examination. No condition trend. The exchanger is returned to service with no more information about its remaining life than it had when it was pulled. This is not a maintenance programme. It is a cleaning schedule.
The Equipment Families — Dominant Failure Modes
Each equipment type in the heat transfer family has a distinct failure profile. Understanding that profile is the prerequisite for designing an inspection strategy that will actually intercept the failure before it becomes an event.
Shell and Tube Heat Exchangers
The Core Process Exchanger
The most numerous heat transfer asset in process industry. Operates as a pressure boundary between two process streams. Failure of tube integrity results in cross-contamination — a process safety and product quality event, not merely a maintenance event. Tube bundle degradation, baffle corrosion, and differential thermal expansion damage accumulate between inspection cycles in a programme that has no measurement basis.
Dominant Failure Modes
Tube wall thinning — corrosion and erosion-corrosion
Tube-to-tubesheet joint failure — crevice corrosion, differential expansion
Under-deposit corrosion — fouling-accelerated wall loss
Baffle corrosion — shell-side flow distribution degradation
Vibration-induced tube damage — flow-induced resonance at unsupported spans
Lube Oil Coolers
The Rotating Equipment Guardian
An oil cooler failure is not a heat exchanger problem — it is a rotating equipment problem. The lube oil system of a turbine, compressor, or large pump depends on the oil cooler to maintain oil viscosity within the bearing design envelope. A degraded oil cooler that cannot hold outlet temperature under load is degrading the bearing film it is supposed to protect. The consequence is not a leaking exchanger. It is a bearing failure in a critical rotating machine.
Dominant Failure Modes
Water-side biofouling — microbiologically influenced corrosion
Oil-side varnish and deposit buildup — thermal degradation of lube oil
Tube pitting — chloride attack on cooling water side
Tube-to-tubesheet weeping — oil-to-water cross-contamination
Thermal performance degradation — masked by outlet temperature drift acceptance
Condensers
Vacuum Service Pressure Boundary
Steam condensers operate under vacuum on the shell side — a condition that inverts the normal failure logic. The pressure boundary does not contain pressure outward; it excludes atmosphere inward. Air inleakage degrades condenser vacuum, reduces turbine backpressure efficiency, and introduces non-condensable gases that accumulate in the steam space and progressively reduce heat transfer surface availability. The waterbox is simultaneously exposed to cooling water chemistry that is typically the most aggressive stream in the plant.
Dominant Failure Modes
Air inleakage — vacuum boundary degradation at flanges, valve glands, expansion joints
Waterbox corrosion — coating failure, galvanic attack at dissimilar metal joints
Tube erosion at inlet — impingement from condensate return and flash steam
Non-condensable accumulation — air binding of tube bundles
Tube pitting — chloride and microbiological attack on cooling water side
Superheaters
High-Temperature Pressure Boundary
Superheaters operate at the highest metal temperatures of any heat transfer equipment in power and process service. The failure modes are thermally driven — creep, high-temperature oxidation, fireside corrosion from fuel ash deposits, and steam-side oxide scale that both insulates the tube wall and spalls into the steam system as a foreign material event. A superheater tube failure under pressure is a sudden, high-energy release in a confined fireside environment. The consequences are severe and immediate.
Dominant Failure Modes
Creep — time-dependent deformation at sustained high temperature
High-temperature oxidation — external tube surface metal loss
Fireside corrosion — sulphidation and vanadium attack from fuel ash
Steam-side oxide scale — insulation effect driving tube metal overtemperature
Thermal fatigue — cycling damage at headers and tube-to-header welds
The Six Programme Failures That Drive Unplanned Events
Heat exchanger failures in industrial service do not generally originate from unpredictable damage mechanisms. They originate from programme failures — decisions made at the maintenance programme design level that guarantee the dominant failure mode will not be detected until it has progressed to an event. The six most consistent programme failures are:
01
Calendar-Based Pull Intervals With No Condition Input
A fixed two-year or four-year pull interval for heat exchanger inspection was established at commissioning and has not been reviewed since. The interval was not derived from a corrosion rate calculation, a fouling rate assessment, or a remaining life estimate. It was derived from convenience and convention. The exchanger that is accumulating damage at twice the assumed rate will not be discovered until the pull. At that point the damage may have progressed beyond a repair threshold. A compliant programme establishes inspection intervals from condition data — corrosion rate trending, thermal performance monitoring, and eddy current history — not from a calendar.
02
Visual Inspection as the Primary Examination Method
Visual inspection of heat exchanger tubes detects surface deposits, gross mechanical damage, and obvious pitting. It does not detect wall thinning. A tube that has lost 40% of its wall thickness to under-deposit corrosion is visually indistinguishable from a new tube after hydroblasting. Eddy current testing is the primary examination method for non-ferrous and stainless tubes. Ultrasonic thickness measurement is used for ferrous tubes and tubesheets. A programme that does not include NDE-based tube examination has no basis for its remaining life estimate — because it has never measured remaining wall thickness.
03
No Tube-to-Tubesheet Joint Examination Protocol
The tube-to-tubesheet joint is the most failure-prone location in a shell and tube exchanger. It is a crevice by geometry. It is subject to differential thermal expansion between the tube and tubesheet. It accumulates corrosion product in the crevice. It is the first location where a tube-side to shell-side leak will originate. Most programmes do not include a specific tube-to-tubesheet joint examination — the joint is included in the visual pass and considered examined. TEMA and API 660 both provide guidance on joint examination requirements. A programme that does not address this joint explicitly is ignoring the most likely failure initiation site in the exchanger.
04
Thermal Performance Monitoring Not Used as a Condition Indicator
An exchanger that is fouling shows it in the process data before it shows it on the tube surface. Outlet temperature drift, increased pressure drop across the bundle, and declining heat transfer coefficient are measurable indicators of fouling accumulation. An operations team that is monitoring these parameters continuously has an early warning system for bundle condition that costs nothing and requires no shutdown. Most facilities do not trend these parameters with any rigour. The first indication of fouling is a process deviation that has already reached an operational impact threshold — at which point the exchanger has been degrading for weeks or months.
05
Cooling Water Chemistry Not Managed as an Integrity Input
The cooling water system is the most aggressive process stream in contact with heat exchanger tubes in most industrial facilities. Chloride concentration, pH, dissolved oxygen, biological activity, and scaling tendency all drive the corrosion rate on the water side. A programme that manages heat exchanger integrity without managing cooling water chemistry is managing symptoms without addressing cause. Microbiologically influenced corrosion from inadequately treated cooling water is responsible for a significant proportion of tube failures in condensers and oil coolers. The biology is in the water. It needs to be managed there.
06
No Plugging or Retirement Criteria Defined in Advance
When eddy current results come back from a bundle examination, the question of what to do with a tube showing 40% wall loss, or 60% wall loss, or 80% wall loss, should already be answered in the programme documentation. The decision should not be made in the field by the person reading the report. TEMA and API 660 provide guidance on tube plugging and retirement criteria. A programme that does not define these criteria in advance will make inconsistent decisions under time pressure — and will return exchangers to service with tubes whose remaining life is not defensible.
The NBIC Position — In-Service Inspection and Repair
Heat exchangers registered as pressure vessels in Ontario are subject to TSSA jurisdiction and the requirements of the National Board Inspection Code. The NBIC governs in-service inspection intervals, repair documentation, and the qualification requirements for inspectors and repair organisations. A heat exchanger repair — tube plugging, tube replacement, tubesheet weld repair, or shell repair — performed outside an NBIC-compliant process is not a documented repair. It is an alteration to a registered pressure vessel without authorisation.
The NBIC requirement is not a bureaucratic formality. It establishes a documented chain of custody for the pressure vessel's condition history — an inspection record, a repair record, and a re-rating record if applicable. That chain of custody is what a TSSA inspector will request on audit, and what a liability investigation will require following a failure. A facility that cannot produce it has a programme gap that extends well beyond the exchanger itself.
NBIC Certification — RISL Credential
RISL holds NBIC certification covering relief valve repair — the National Board Inspection Code qualification governing the repair, testing, and re-certification of pressure relief devices on boilers and pressure vessels. RISL assessments of heat exchanger integrity programmes are conducted against NBIC requirements, TEMA service classifications, API 660 recommendations, and TSSA Ontario regulatory obligations. The assessment produces a documented gap register, a condition baseline, and an execution-grade corrective programme — not a report.
What a Compliant Heat Exchanger Integrity Programme Contains
A programme that will actually intercept heat exchanger failures before they become events contains the following elements — all documented, all executed, all producing records that support the next inspection interval decision.
Asset Register and Service Classification
Every heat exchanger in the facility is registered with its TEMA class designation, design pressure and temperature, tube material, shell material, process streams (tube-side and shell-side), and cooling water chemistry designation where applicable. TEMA classes R, C, and B define different construction and examination requirements — a programme that does not record the TEMA class of its exchangers cannot claim to apply the correct standard.
Risk-Based Inspection Interval Setting
Inspection intervals are derived from a risk ranking that considers the consequence of failure (process stream cross-contamination, rotating equipment damage, environmental release, personnel exposure) against the likelihood of failure (corrosion rate from previous inspection history, fouling rate from thermal performance trend, service severity). API 581 provides the RBI methodology framework. The interval that results from this process is defensible — it is anchored to condition data and consequence assessment, not convention.
NDE-Based Tube Examination
Every bundle pull includes eddy current testing (ECT) for non-ferrous and austenitic stainless tubes, or ultrasonic thickness measurement for ferrous tubes, across a statistically representative sample — minimum 10% of tubes, with targeted 100% examination of tubes in the highest-degradation zones identified in previous surveys. Results are trended against previous examinations. Corrosion rate is calculated. Remaining life is estimated. The next inspection interval is set from that estimate.
Tube-to-Tubesheet Joint Protocol
A specific examination of tube-to-tubesheet joints is performed at every pull, documented separately from the tube body examination. Leak testing of individual joints is performed where the service consequence of a tube-side to shell-side leak is high. The joint examination record is part of the exchanger's permanent condition history.
Thermal Performance Monitoring
Inlet and outlet temperatures on both sides, flow rates, and pressure drop across the bundle are monitored continuously or at defined intervals and trended against the clean design performance. A fouling factor is calculated from operating data. When the fouling factor exceeds a defined threshold — set in the programme, not determined in the field — an inspection and cleaning is triggered regardless of the scheduled pull date.
Plugging, Repair, and Retirement Criteria
Tube plugging criteria are defined in the programme: maximum percentage wall loss before plugging is required, maximum number of plugged tubes before bundle replacement is required, and retirement criteria for tubes showing evidence of pitting or cracking that cannot be characterised by the NDE method in use. These criteria are set by engineering before the inspection, not determined by the inspector during the pull.
The Governing Standards
Applicable Standards and References
TEMA
Standards of the Tubular Exchanger Manufacturers Association — design, fabrication, and maintenance standards for shell and tube heat exchangers; Classes R (refinery), C (commercial), and B (chemical process)
API 660
Shell-and-Tube Heat Exchangers for General Refinery Service — specifies requirements for design, materials, fabrication, inspection, and testing of shell and tube exchangers in petroleum service
ASME Section VIII Div. 1
Rules for Construction of Pressure Vessels — pressure boundary design and construction requirements applicable to heat exchanger shells, channels, and heads as registered pressure vessels
NBIC — NB-23
National Board Inspection Code — in-service inspection, repair, and alteration requirements for registered pressure vessels including heat exchangers; mandatory under TSSA in Ontario
API 581
Risk-Based Inspection Methodology — provides the quantitative and semi-quantitative framework for consequence of failure and probability of failure assessment to establish RBI-based inspection intervals
ASME PCC-2
Repair of Pressure Equipment and Piping — repair methods and qualification requirements for heat exchanger tube plugging, tube replacement, and pressure boundary weld repairs
ISO 55001
Asset Management — System Requirements — framework for a documented heat exchanger integrity programme as part of a compliant asset management system with defined risk criteria and performance monitoring
TSSA O. Reg. 220/01
Ontario pressure systems regulation — governs in-service inspection frequency, repair documentation, and TSSA notification requirements for registered heat exchangers as pressure vessels
The Consequence of Programme Absence
A heat exchanger that fails in service does not simply stop working. In shell and tube service, tube failure means the two process streams it was keeping separated are no longer separated. If one stream is a hydrocarbon and the other is cooling water, the consequence is hydrocarbon contamination of the cooling water circuit — a fire and environmental exposure that extends well beyond the exchanger. If one stream is lube oil and the other is cooling water, the consequence is bearing system contamination and the progressive failure of the rotating equipment the oil system was protecting.
In condenser service, tube failure introduces cooling water into the steam cycle — a water chemistry event that affects every piece of equipment downstream. In superheater service, tube failure under pressure in the fireside is a sudden high-energy release in an enclosed, high-temperature environment.
None of these consequences is proportionate to the cost of a programme that measures tube wall thickness, trends thermal performance, manages cooling water chemistry, and sets inspection intervals from condition data. The programme cost is known and manageable. The failure consequence is neither.
TEMA
API 660
API 581
ASME Section VIII
ASME PCC-2
NBIC
Shell and Tube
Oil Coolers
Condensers
Superheaters
Eddy Current Testing
RBI
ISO 55001
TSSA
Fouling
Tube Integrity