Hot-end tubes account for roughly half of Heat Recovery Steam Generator failures, and non-destructive testing is increasingly the difference between planned maintenance and $200,000–$300,000 per hour outages. Inside the playbook that pairs modern NDT with tight chemistry control—and why the ROI is measurable.
Heat Recovery Steam Generators (HRSGs)—the heat exchangers that turn gas-turbine exhaust into steam in combined-cycle plants—carry high-pressure steam and live with thermal, corrosion, and fatigue stresses. Industry data spanning more than 100 plants show hot-end tubes (superheaters/reheaters) suffer about 50% of failures, with creep/fatigue roughly 40% and corrosion about 23% as leading damage modes (www.tetra-eng.com) (www.powermag.com).
Fatigue cracks from thermal transients account for about 23–25% of failures, corrosion roughly 19%, and other causes (fabrication defects, tensile overload) about 10–12% each (www.nsenergybusiness.com). In practice, tube leaks concentrate in economizers (about 50% of leaks, from fatigue or corrosion) and superheater sections (about 25% of leaks, often at tube‑header welds) (www.power-eng.com). A comprehensive maintenance program—frequent inspections combined with corrective actions—sits at the center of avoiding forced downtime and high expense (www.powermag.com).
Failure patterns and inspection targets
Routine HRSG maintenance blends visual and instrumented inspection of pressure parts (drums, headers, tubes) and gas‑side components with tight water/steam chemistry control. Visual drum inspections can reveal loose deposits or black magnetite—an indicator of failing boiler water treatment (www.power-eng.com). Video‑borescope exams through drum taps are standard to inspect internal tube surfaces for under‑deposit corrosion or FAC (flow‑accelerated corrosion, metal loss from high‑velocity water/steam chemistry) in feedwater circuits (www.power-eng.com) (www.vogtpower.com).
On the gas side, inspectors check duct liners, burner hardware, expansion joints, and silencers for cracks or damage (www.power-eng.com). Tight spacing in tube banks frequently pushes teams beyond visual checks to instrumented NDT (www.power-eng.com) (www.power-eng.com). “Table arcing is also done: e.g. abundance of FAC in LP/IP economizers means UT thickness mapping is performed to spot wall thinning before failure” (www.power-eng.com) (www.vogtpower.com).
Ultrasonic thickness mapping (UT)
Ultrasonic Testing (UT) thickness gaging is the workhorse for detecting tube wall loss, especially FAC. Plants typically map all FAC‑prone areas (economizers, ATDR piping) with handheld UT during outages, recording measurements in a baseline grid for trending (www.power-eng.com) (www.vogtpower.com). UT with special probes or phased‑array scanning also interrogates welds; it is “well‑recognized” for locating FAC thinning (www.power-eng.com).
In one Indonesian study, engineers combined ultrasonic thickness checks with hardness tests and replica analysis on 25‑year‑old boiler tubes and estimated remaining life on the order of 100,000–120,000 operating hours (js.bsn.go.id). Quantitative wall‑loss curves from such surveys sit at the core of predictive maintenance.
Eddy current and pulsed electromagnetic methods
Eddy‑current testing (ECT) is widely used for surface‑crack detection and wall‑thickness estimation in HRSG tubes, including ferromagnetic carbon steels. Remote‑field or near‑field eddy currents can penetrate beyond fins. One field case developed a Near‑Field Array (NFA) eddy‑current probe inserted through tube headers to scan finned tubes internally, yielding C‑scan images of corrosion/erosion where external access is limited (www.ndt.org).
Pulsed eddy current (PEC) has advanced non‑contact thickness screening. A commercial PEC probe (Eddyfi Lyft) detected 0.067–0.133″ deep ID wall‑loss defects in a 7.09 cm OD tube over fins from outside the tube, even through oxide layers (www.eddyfi.com) (www.eddyfi.com). After optimized signal processing, PEC imaging “successfully demonstrated” ability to detect inner corrosion through fins and sludge (www.eddyfi.com) (www.eddyfi.com). Such external scans quickly map wall thinning over large tube sections without cutting headers, reducing inspection time and on‑site costs. Overall, AC techniques (multi‑channel arrays, rotating AC, etc.) complement UT by reaching areas inaccessible to straight‑line ultrasound.
Remote visuals and infrared thermography
Visual checks remain essential for leaks, baffle issues, weld defects, or insulation damage. High‑resolution borescopes and drones extend views inside steam paths or gas ducts (www.vogtpower.com) (www.vogtpower.com). Infrared thermography during operation or walkdowns can spot hot/cold spots on economizer banks or leaking joints; service vendors offer IR surveys to find steam‑water leaks or overheated supports (www.vogtpower.com).
Thermal imaging is not a primary flaw detector but helps prioritize NDT focus. In practice, visual/thermal methods serve as first‑pass screening that lead to UT or MT/PT (magnetic particle and liquid penetrant) follow‑ups.
Crack, weld, and life assessment
Liquid Penetrant (LP) and Magnetic Particle Inspection (MPI) are applied to welds, flanges, and suspect fittings. With many failures initiating at welds or transitions, MPI on header welds and tube‑to‑header joints is included in major outages (www.power-eng.com). Replica metallography (polishing and etching a small surface to image microstructure) assesses creep or fatigue in high‑temperature superheater tubes (js.bsn.go.id).
Acoustic‑emission (AE) monitoring is sometimes used to detect crack growth during startup; sensors on superheater spray valves or attemperators track dynamics to prevent thermal shocks—since attemperator leaks cause reheater thermal fatigue (www.nsenergybusiness.com).
Other screening and leak detection
Guided‑wave UT can screen long runs of accessible piping for gross defects, though with limited resolution. Radiographic testing (RT) is seldom feasible for tightly bundled HRSG tubes. Some plants turn to direct leak detection borrowed from fossil units: helium injection into drums with stack sniffers, or on‑line acoustic leak detectors (www.power-eng.com) (www.power-eng.com).
Preventive program and chemistry control
Preventive maintenance (PM) spans scheduled plant walkdowns, routine water chemistry control—e.g., AVT(O) (all‑volatile treatment with oxidizing conditions) to suppress FAC—and logging of key parameters, periodic off‑line inspections, and immediate chemistry/cleaning actions on warning signs (www.power-eng.com) (www.powermag.com). In practice, accurate dosing and pH‑conditioning underpin that control; equipment such as a dosing pump and programs built on a neutralizing amine or alkalinity control strategy are frequently part of the toolkit.
Each outage commonly includes, at minimum, borescope/visual inspection of all tube bundles, UT thickness surveys of FAC‑prone sections, and MPI of critical welds (www.power-eng.com) (www.vogtpower.com). Newer techniques—PEC scanning over fins (www.eddyfi.com) (www.eddyfi.com), guided‑wave probes, online thermography—are expanding coverage.
Case studies, costs, and ROI
Maintenance investment yields measurable gains. At a 28‑year‑old Indonesian CCPP (Belawan), replacing an aging HRSG tube bank increased unit reliability by 13.7% and availability by 1.6%, with a calculated NPV of roughly IDR 3.6×10^11 (about USD 23M) and an internal return around 7.5% (www.researchgate.net). Previously, tube leaks had derated the steam turbine by about 50%, sharply reducing the plant’s Equivalent Availability Factor (www.researchgate.net).
On a broader scale, unplanned outages cost about $200–300K per hour on average, and equipment failure causes roughly 42% of unscheduled downtime in industrial plants (txidigital.com). Condition‑based maintenance can boost uptime by 10–20% and cut material, inventory, and labor costs by similar margins (txidigital.com). Service firms report that more than 90% of existing plants have latent performance gains if properly inspected (www.vogtpower.com), and comprehensive UT mapping plus videoscope inspection almost always uncovers FAC or corrosion in evaporator/economizer tubes that need action (www.vogtpower.com) (www.vogtpower.com).
Small problems compound. Just a 1/64″ (0.4 mm) layer of iron/silica scale on tube walls can reduce heat transfer and efficiency by about 3.5% (www.powermag.com). Cleaning actions and scale‑mitigation regimes—such as a focused scale-control program or scheduled work via a boiler cleaning service—help avoid the incremental derates. Properly maintained units “can run well for decades” (www.powermag.com).
Operating trends and asset integrity
Industry trends toward flexible cycling increase HRSG stress and change failure modes, making maintenance even more crucial (www.nsenergybusiness.com). A data‑driven PM approach—paired with modern NDT and strict chemical control—detects early damage, enables repairs on a plant’s schedule, and avoids the safety risk and cost of emergent failures. Integrating reliability and risk analysis into maintenance decisions is now standard practice in Indonesia and elsewhere (www.researchgate.net), whereas “haphazard” inspection programs risk unscheduled outages and safety hazards (www.power-eng.com).
Sources and further reading
Data and figures are drawn from industry reports and studies: Tetra Engineering and industry analyses (www.tetra-eng.com) (www.nsenergybusiness.com) (failure distributions), Rentech/Bremco and other HRSG maintenance guides (www.power-eng.com) (www.powermag.com), technical case studies (www.ndt.org) (www.eddyfi.com) (www.researchgate.net) (js.bsn.go.id), and predictive‑maintenance assessments (txidigital.com) (txidigital.com) (www.vogtpower.com).
