Written by Alejandro Rodas | Power Plants
Every HRSG operating in the United States is subject to a jurisdictional inspection, typically on an annual basis. A National Board–commissioned inspector, working either for the insurance carrier as an Authorized Inspection Agency or for the state, carries out these inspections. The inspector examines the pressure boundary: drums, safety valves, pressure parts, and external deaerator tanks. The purpose is to verify that the equipment is safe to operate under code.
But safe to operate isn’t the same as ready to run well. The gas path falls outside that scope entirely. Liners, casing, expansion joints, penetration seals, and duct burners retain no pressure, so the inspection was never designed to reach them.
Why Are Jurisdictional Inspections Not Enough?
They leave a gap. A unit can satisfy every jurisdictional obligation and still not have had a qualified, comprehensive look at its gas path. Compliance establishes that the unit may legally operate. It says nothing about the state of the rest of the unit, or about what the next outage will cost. Assessing HRSG condition falls to the plant, whether through its own staff or contracted specialists.
Most currently installed HRSG units were engineered for baseload service, and many now operate on cycling duty, run at low load, and ramp faster than the original design accounted for. Thermal cycling and layup corrosion accumulate damage faster than annual inspection intervals assumed. Faults therefore develop between mandated inspections rather than on schedule.
Those faults compound. A failed stud lets a liner plate shift, and what began as a stud repair can end as liner, insulation, casing, and catalyst work. Creating and implementing HRSG inspection checklists used between jurisdictional inspections is necessary to maintain efficiency and avoid unplanned downtime.
What Can Be Checked While the Unit is Online?
Some conditions can only be observed while the unit is running because they exist only during hot operation. Much of that evidence is logged in the control room. Gas-side backpressure trended against OEM prediction at matched load, and attemperator downstream temperature compared to upstream with the spray valve closed, both point to developing problems well before anything is visible in the gas path. A field walk covers what the instruments never read at all. This includes but is not limited to casing surface temperature, duct vibration, and pipe movement at floor penetrations during startup.
Findings from online inspections set the scope for any offline inspections and repairs. For example, hot spots logged while running will tell the crew exactly where to open the unit during the next outage. Long-lead items identified before shutdown can be engineered and procured in time to be corrected in that outage, rather than waiting for the next one. Here are some items to include in online inspections and what they may point to.
Gas-side backpressure trending against prediction
Compare backpressure to the unit’s own baseline at the same load and ambient conditions rather than to a fixed number. Absolute values vary with configuration, catalyst, and stack. A rising trend indicates gas path fouling, baffle damage, or debris liberated from a failed liner. It costs turbine output and heat rate the entire time it goes uncorrected. Trend the rate of rise. A slow climb can be scoped for the next outage, while a sudden step change suggests something has just let go.
Attemperator downstream temperature below upstream with the spray valve closed. Compare the readings across the valve rather than against a setpoint. A temperature drop with the valve shut means water is passing a valve the control system indicates is closed, and that water reaches metal at operating temperature. Leak-by is a leading source of quench damage in downstream piping and tube-to-header welds. Spray valve repair belongs in the current window where the schedule allows, along with a look at the desuperheater drains.
Casing hot spots and discolored paint
Check penetrations, access doors, expansion joints, and field joints. Most heat-resistant paint discolors above roughly 350°F, which makes discoloration a visual tell for exhaust gas reaching bare casing behind a failed liner or lost insulation. Restrained thermal growth cracks casing steel, particularly in stiff roof and floor sections. Map the area with an infrared survey and mark the location for offline access. A spot that grows between surveys carries more weight than any single high reading.
Inlet duct vibration and casing pulsation
Rattling or flapping felt on the casing during operation indicates loose liner sheets, baffles, or flow distribution plates moving in the gas stream. Repeat liner failures in a duct that vibrates can trace to too few casing stiffeners, which is a design shortfall rather than a maintenance one. Schedule the repair for the next outage, recognizing that an in-kind replacement may not hold if the cause is structural.
Drain valve leak-by
Temperature downstream of a closed drain valve, or drain pot level behavior indicating passing flow, means condensate is reaching hot metal before steam admission. It is the other main quench source alongside attemperator leak-by. The correction is partly valve repair and partly startup and drain timing practice.
Not every finding leads to a repair. For instance, economizer outlet temperature that nears drum saturation is an operating and control fix. But all the other items listed above narrow what a crew will need to look for once the unit is offline for an outage.
What Inspections Require Shutdown and Access?
Offline inspection items require HRSG shutdown for safety reasons as well as practicality. Many are indicated, however, by the online inspections listed above. The checklist items below sit entirely outside the certificate inspector’s scope. While many plants are staffed by personnel with deep gas and steam turbine expertise, many, if not most of them, don’t have an on-staff, on-site HRSG specialist. An outside contractor can fill that gap.
Because the outage window often shares or is guided by the gas turbine schedule, offline access may be limited and shared with other work. This may cause some important areas to be skipped or scanned through quickly. Two such areas are the crawl spaces above and below headers. But they are significant inspection points. What follows are some other important checklist items.
What about NDE?
Visual inspection can detect many problems, but several of the most important damage mechanisms in HRSGs start forming before they become visible. It is recommended to use non-destructive evaluation (NDE) in addition to visual inspection, selecting methods based on the individual plant’s risk profile, namely ultrasonic thickness testing (UT), magnetic particle testing (MT), dye penetrant testing (PT), tube sampling, and flow-accelerated corrosion (FAC) monitoring when applicable.
Scope of NDE will depend on specific features of individual HRSG and its history of operation. The information obtained from NDE must be used together with information from operation and chemistry studies and visual inspection to set priorities for outage repairs.
Loose liner plates, failed studs, and exposed insulation
Check the inlet and firing duct for shifted plates, failed studs, and exposed insulation. An isolated failure is wear, correctable in the current window. Repeated failures in one section point to an attachment problem needing further analysis to repair effectively during the next outage.
Expansion joint deterioration and flange distortion
Look for splitting or hardening in fabric joints, cracking in metallic bellows, and flange faces out of true. Leakage can let exhaust bypass emissions control equipment. Flange condition drives the schedule more than the joint itself, so measuring it now is what makes the replacement plannable.
Penetration seal damage and missing liner donuts
Seals accommodate axial growth, but tube panel bowing adds lateral movement they weren’t built to take. The seal fails first, though the movement driving it starts elsewhere. Replacing it without addressing what is moving returns the same finding later, so handle it alongside a check of support position.
Debris on the SCR catalyst face
Insulation fibers, rust flakes, and liberated hardware reduce active surface and raise backpressure, which is what the running-unit trend was registering. The debris collected here but started upstream. Cleaning the face buys a cycle. Tracing the source is what keeps it clean.
Water staining or wet insulation below tube bundles
Leaks are usually easy to spot even where the tube isn’t accessible, but a clean visual isn’t always a clean bill of health since flow-accelerated corrosion thins tubes invisibly. A single leak is a tube repair or pad weld now. Wall loss across a panel points toward replacing the tube panel assembly, which carries its own lead time. Either way, work on pressure-retaining items in general falls under the National Board Inspection Code, which requires the organization performing it to hold an R Certificate of Authorization.
Cracking at tube-to-header and drain welds
Thermal fatigue produces some of it. The rest comes from water reaching hot metal, the same condition the attemperator and drain readings flagged while running. The valve finding and the weld crack are one problem at two stages. Repairing the crack without correcting the source pushes rework later.
One gas path component sits outside both lists. The stack runs on its own inspection intervals and carries an inspection checklist of its own.
Why Do Some Findings Keep Coming Back?
Every item on both checklists is often a symptom requiring further investigation. A finding that reappears in the same location at successive inspections is reporting something the repair didn’t address. It could be cycle chemistry, startup and shutdown practice, drain and attemperator arrangement, or original design and installation quality.
That distinction decides what a repair is worth. Replacing a liner panel under outage pressure restores the panel and buys one more cycle. Correcting what moved it, or specifying chrome-bearing alloy at elbows losing wall to flow-accelerated corrosion, costs more upfront. But it stops the fault from returning.
Findings on a single unit rarely stay in one repair category. A harp replacement alone spans engineering, fabrication, and installation, and it has to be researched before the next outage rather than during it. Whether that work sits with one contractor or with several coordinated across the outage window is a planning decision worth making early.
Creating Your Own Specialized HRSG Inspection Checklist
The inspection checklist above is certainly not exhaustive nor all-inclusive. It’s presented as a springboard for creating your own, specific to your facility. You might want to download our free Stack Inspection Checklist to give you a head start and help you formulate your HRSG inspection checklist.
Here’s one last thought, coming from the field of maintenance, troubleshooting, and repair: “When all else fails, read the manual.” The documentation and field owner’s manual the manufacturer included with your HRSG may very well contain tips on building an inspection checklist, and might even have one laid out for you to use.