Tube failures in heat recovery steam generators are a leading cause of forced outages—and a single rupture can run to about €120 million. The playbook now: targeted non‑destructive testing plus disciplined preventive maintenance.
Heat recovery steam generators (HRSGs—heat exchangers that turn gas‑turbine exhaust into steam) pack thousands of finned and unfinned tubes into tight bundles, making them both vital and vulnerable (Power Engineering) (Tetra Engineering). As plants cycle more frequently—many now start and stop daily—damage accelerates from creep (time/temperature aging), thermal/mechanical fatigue, and flow‑accelerated corrosion (FAC—water chemistry dissolves protective oxides on carbon steel) (Power Engineering) (Power Engineering).
Just a 10 °C rise in operating temperature can halve creep life, a stark illustration of how “seemingly minor changes” rewrite remaining life calculations (Power Engineering). Tube failures remain a leading cause of forced HRSG outages, and a single superheater‑tube rupture in a steam plant has been costed at about €120 million (Power Engineering) (CORDIS). The reliability of these units directly drives plant ROI (Power Engineering) (CORDIS).
Damage modes and cycling duty
Flexing for market demand raises metal temperatures and cycle counts, exacerbating creep, fatigue, and FAC in pressure parts (Power Engineering) (Tetra Engineering). Industry case histories show that, under increased cycling, leaks have occurred after only a few thousand service hours if maintenance and inspection lag (Tetra Engineering).
FAC often presents an “orange‑peel” or scalloped internal surface as thinning progresses (Power Engineering). Thermal fatigue drives circumferential and axial cracking at low‑temperature headers or inlets; advancing ultrasonic techniques have increased the detectable defect count in these zones (Power Engineering).
NDT toolkit for tube integrity
Inspection hinges on non‑destructive testing (NDT—methods that assess materials without cutting them). Visual testing (VT) remains first line: annual “naked‑eye” inspections with good lighting at under 60 cm from the surface flag insulation damage, external erosion, leaks, or fouling; borescopes extend VT into drums and tube bundles to spot bulges, pitting, or tube‑to‑header cracks (Intertek) (Tetra Engineering). Even a simple visual exam can catch early one‑area damage that would otherwise cascade into extensive shutdowns if ignored (Tetra Engineering).
Ultrasonic testing (UT—sound waves for thickness and flaw detection) maps wall loss from corrosion/erosion and detects cracks. Phased‑array UT can size multiple closely spaced axial cracks in headers that single‑angle UT might only detect (Power Engineering). Guided‑wave UT scans survey long header runs for thinning without segmenting piping.
Eddy‑current testing (ECT—electromagnetic inspection for conductive metals) lifts the veil on near‑surface flaws. Pulsed eddy‑current (PEC) works through external fins, enabling assessment of internal wall thinning in finned economizer/evaporator tubes without strip‑out—useful for FAC and dew‑point corrosion checks (Intertek). Near‑field array (NFA) ECT has demonstrated accurate depth measurement of artificial FAC grooves and pits in HRSG tubes, with measured depths closely matching actual values (Power Engineering). Standard rotating‑probe ECT also screens superheater tubes and steam drum waterwall panels.
Radiography (RT—X‑ray or gamma) exposes weld defects in tube‑to‑header joints, manifolds, and thick sections; computed/digital radiography shortens turnaround with higher sensitivity, though RT is usually offline on removed sections. Surface methods—liquid‑penetrant (PT) and magnetic‑particle inspection (MPI)—find tight cracks at welds, valves, and drums when surfaces are cleaned; plants routinely use them at known fatigue hotspots during outages.
Acoustic emission (AE—listening for crack growth) and leak detection extend coverage. AE arrays on drums or thick pipes monitor activity in real time; ultrasonic or infrared point sensors find pressurized steam leaks on‑line. Thermography during outages reveals hot spots or flue‑gas leaks around casing and tubes.
Combining methods is standard: a suspected FAC zone might be UT‑mapped for thickness, borescoped for pitting, and validated with PEC. If NDT flags unusual corrosion or creep, selected tubes are sent for metallography to confirm mechanisms and refine repairs and life assessments (Intertek).
Intervals, hotspots, and baselining
Baseline deep‑entry inspections early in life, then at major outages, anchor trendlines (Tetra Engineering) (Tetra Engineering). In the US, code typically mandates annual HRSG inspections; in practice, many plants run external VT each outage and full internal NDE every 3–5 years or per duty cycle (Tetra Engineering). Inspectors prioritize high‑risk areas—economizer bends, LP evaporator downcomers, LP headers—where damage clusters.
Tetra’s experience across 750+ HRSG inspections shows neglected units can harbor localized thinning and cracking that standard codes did not predict, reinforcing the case for duty‑based intervals and hotspot targeting (Tetra Engineering) (Power Engineering).
Preventive maintenance and reliability payback
A robust preventive‑maintenance (PM) program turns inspection findings into action. Routine maintenance—chemical cleaning, sootblowing, leak checks, water treatment, valve servicing—pairs with periodic deep inspections every 12–24 months to catch and correct small problems before failure (Intertek). Even basic annual outage visuals can reverse early degradation and prevent a sudden reliability drop (Tetra Engineering).
Plants commonly align PM scopes with specialty services and supporting equipment already embedded in operations, such as chemical cleaning delivered by a professional boiler cleaning service, water‑treatment ancillaries during outages, precise chemical addition via a dosing pump, and a managed boiler‑chemistry program sourced from boiler chemicals.
The economics are documented. At Indonesia’s Belawan combined‑cycle plant, choosing to replace leaking HRSG tubes rather than ride out degradation raised HRSG reliability by 0.137 and availability by 0.016 (unitless scaled metrics), with a net present value of IDR 3.60×10^11 (approx. USD 25 million) and an IRR around 7.5% (ResearchGate) (ResearchGate). A separate reliability‑centered maintenance study on an industrial steam boiler reported ~20% annual maintenance cost reduction alongside higher availability after instituting structured PM (MDPI).
Risk‑based targeting and design codes
Risk‑based maintenance focuses inspection where models and operating data predict stress and corrosion. Once high‑risk locations are known, plants can apply the most effective inspections to those zones (Power Engineering) (Power Engineering). In Europe, design codes such as EN 12952 embed fatigue analysis and life calculations for boiler pressure parts, codifying maintenance planning around predicted damage (Power Engineering). While HRSGs may not be the single costliest plant component, their life‑management demands loom large in the cost base and revenue risk of deregulated markets (Power Engineering).
System‑level effects are clear: reliability modeling of a 500 MW combined‑cycle plant found that improving HRSG maintenance nudges overall availability toward design targets because the chain is limited by its weakest link (ResearchGate) (ResearchGate). Conversely, as cycling ratchets up, documented leaks within just a few thousand hours reinforce the case for adjusting inspection frequency to actual duty (Tetra Engineering).
Regulatory oversight and documentation
Most jurisdictions require periodic boiler inspections; in the US, annual examinations are typically statutory or insurer‑driven (Tetra Engineering). Standard practice documents maintenance, and major components—drums, tubes, piping—are pressure‑tested or otherwise verified safe before return to service. Organizations frequently adopt standards such as ASME I, API 510, and SNI to govern pressure‑part inspections.
Bottom line for availability
Visual and borescope checks identify obvious deterioration; UT and eddy‑current quantify wall thinning; radiography, phased‑array UT, and acoustic emission root out hidden cracks; PT/MPI catch surface defects at welds. Focused on high‑risk areas, these methods surface most service damage before it fails in service (Tetra Engineering) (Power Engineering).
Tying it together is preventive maintenance with regular outages and condition monitoring; industry and research analyses show such programs lift reliability and reduce costs—about 20% lower annual maintenance costs in one study—and protect the capital investment (MDPI). Given the stakes—including that ~€120 million rupture example—robust inspection and PM, aligned with regulatory requirements, are now table stakes for safe, profitable operation (Power Engineering) (Power Engineering) (CORDIS).
