A 5.5 MW gas turbine pushed to 9,600 fired hours without a combustion inspection does not fail politely. The liner cracks, the transition piece distorts, and hard debris goes straight into the first stage nozzle. A planned six day outage becomes a nineteen day forced one, and the bridging diesel bill alone runs into a large multiple of what the deferred inspection would have cost. Gas turbine inspection intervals exist to stop that arithmetic, and the numbers behind them are not arbitrary.
Most maintenance managers already know the headline figures: combustion inspection near 8,000 hours, hot gas path near 24,000, major overhaul near 48,000. What gets applied less carefully is that these are factored hours, not hours on the running meter. The factors are where Nigerian plants quietly lose their margin.
Why gas turbine inspection intervals are counted in factored hours
Two counters run in parallel on any heavy duty gas turbine: fired hours and starts. Whichever limit arrives first sets the inspection. Continuous duty plants are usually hours limited. Plants that stop and start with load shedding, grid instability or shift patterns are often starts limited, and they are frequently surprised by it.
Factored hours apply a severity multiplier to actual running hours. Firing on natural gas is the baseline. Distillate typically carries a factor around 1.5 on hours, and heavy or residual fuels can carry 3 or more because of ash deposition and hot corrosion. Peak firing, water or steam injection for NOx control, and sustained operation above base load each add further multipliers.
Starts are factored the same way. A normal start followed by a controlled shutdown counts as one. An emergency trip from base load is commonly counted as 8 equivalent starts, and a trip from peak load can be counted at 20, because the thermal transient through the hot section is severe. Fast starts and fast loading carry their own penalty.
This is why two identical machines with the same hour meter reading can sit at completely different points on the maintenance ladder. If your factoring assumptions have never been checked against the actual operating log, a power plant audit is the cheapest way to find out where you really stand. Request a technical proposal and we will scope the data review before anything is opened.
The effect is not theoretical. Worked example (hypothetical): a 15 MW dual fuel unit loses gas supply for five months, so the machine runs roughly 3,500 hours on distillate. At a severity factor of 1.5, those hours count as 5,250 factored hours against the hot gas path limit. The inspection the budget had placed in the following financial year arrives nearly eight months early, and the long lead parts have not been ordered.
The three inspection levels: combustion, hot gas path and major overhaul
Combustion inspection is the shallowest of the three and the one most often deferred. The unit is opened at the combustion section only. Liners, transition pieces, fuel nozzles, crossfire tubes, igniters and flame detectors come out for inspection, measurement and either repair or replacement. The rotor stays in place and the casings are not lifted. On a mid sized industrial machine this is a five to eight day outage with a competent crew and parts already on the ground.
Hot gas path inspection includes everything in the combustion inspection and adds the first and second stage nozzles, buckets and shrouds. Upper casings are lifted, so the outage is longer and the rigging requirement is real. Coating condition, creep, cooling hole blockage and crack indications on the buckets drive the repair or replace decision. Expect two to three weeks, longer if parts must travel abroad for refurbishment.
Major overhaul, sometimes called major inspection, takes the machine apart. Compressor and turbine casings are opened fully, the rotor is normally removed, bearings and journals are inspected, compressor blading is examined for erosion and fouling damage, couplings and the load gear come under scrutiny, and clearances are reset. Non destructive testing on the rotor is part of the scope, not an optional extra. Four to six weeks is realistic, and a rotor life assessment can extend that.
Between these levels, borescope inspections every 4,000 hours or annually give you a bridging view without opening a casing. They are useful and they are not a substitute. A borescope will show you a cracked liner. It will not tell you the residual creep life of a bucket. If you want the full parts list and hold points that belong in a tender document, our note on the turbine overhaul scope of work sets them out.
What shortens gas turbine inspection intervals in Nigerian operating conditions
Air quality is the first factor and the most under managed. Compressor fouling from dust, salt near the coast and hydrocarbon aerosols on oilfield sites reduces output and raises exhaust temperature at a given load. Firing harder to hold output then accelerates hot section consumption. Harmattan makes this seasonal and severe, which we cover separately in harmattan dust and turbine derating.
Filtration class matters more than most sites budget for. Moving from a coarse pre filter arrangement to a properly staged system with high efficiency final stages costs money once and pays back through slower fouling, longer gaps between offline washes and lower risk of blade erosion. Online water wash restores some performance. Offline crank wash restores more. Neither reverses erosion damage, and no filtration system removes the need for the physical inspection at the interval.
Fuel quality is the second factor. Associated gas with liquid carryover, variable heating value or high sulphur content will shorten hot section life whatever the hour meter says. Gas conditioning at the skid, knockout drums, coalescing filtration and superheat control are not optional on a machine you intend to run to a published interval.
Grid and process instability is the third. Frequency excursions and load rejections produce trips, and trips are counted at 8 equivalent starts or worse. Worked example (hypothetical): an installation running twin aeroderivative units sees twelve emergency trips over one year, mostly from downstream process upsets, contributing roughly 96 equivalent starts. That consumes close to a quarter of the annual start based allowance without adding a single running hour. Most of those trips trace back to instrumentation and fuel system faults rather than the turbine itself, which is the usual finding. Our breakdown of gas turbine trip causes works through the common ones.
Ambient temperature affects output rather than interval directly. The operational response to it, firing harder to recover lost megawatts, is what moves the interval.
What each inspection level involves and what it buys you
The table below is indicative for a 5 MW to 6 MW class industrial gas turbine on natural gas at a Nigerian site with reasonable access. Figures move with parts scope, exchange rate, whether hot parts are repaired or replaced, and whether refurbishment is done locally or overseas. Treat it as a planning envelope, not a quotation.
| Inspection level | Typical interval | Start based limit | Outage window | Main scope |
|---|---|---|---|---|
| Borescope | 4,000 factored hours or annual | not applicable | 1 to 2 days | Visual internal check, no casing lift |
| Combustion inspection | 8,000 factored hours | about 400 factored starts | 5 to 8 days | Liners, transition pieces, fuel nozzles, crossfire tubes, igniters |
| Hot gas path inspection | 24,000 factored hours | about 1,200 factored starts | 14 to 21 days | The above plus stage 1 and 2 nozzles, buckets and shrouds, casing lift |
| Major overhaul | 48,000 factored hours | about 2,400 factored starts | 28 to 42 days | Full strip, rotor removal, NDT, bearings, compressor blading, clearances |
Cost rises steeply between levels, and parts scope, whether hot parts are repaired or replaced, and whether refurbishment is done locally or overseas move the number far more than the interval itself does. See our cost guide for the drivers behind each level.
The number that belongs beside this table is the cost of not doing the work. Worked example (hypothetical): a single 5.5 MW unit running roughly 7,800 hours a year defers its combustion inspection to 9,600 fired hours to protect a peak production quarter. The liner fails. Downstream nozzle damage pulls the job up to hot gas path level, and the machine is off line for nineteen days.
Bridging on diesel against gas, at an average 3.2 MW load for nineteen days, adds a large fuel differential on its own, before counting production losses. The deferred combustion inspection would have cost a small fraction of the hot gas path repair it triggered.
If your unit is approaching a level change and the parts lead time is not yet fixed, book a plant assessment before the window closes. Long lead hot section components routinely run four to eight months door to door.
Planning the outage window, spares and specialist scope
Three things decide whether an inspection lands on schedule: parts availability, crew competence and lifting access. Parts are the usual constraint in Nigeria. Hot section components are rarely stocked locally, and shipping plus clearance adds weeks that no amount of planning at the plant will recover.
Make the parts decision early. For hot gas path and major work you are choosing between new OEM parts, OEM refurbishment, qualified third party repair, and holding a rotable set against the next outage. A rotable strategy costs capital up front and buys back outage days, which is the right trade wherever a day of downtime costs more than the carrying cost of the set.
Do not attempt casing lifts, rotor removal or clearance setting without correct rigging, calibrated tooling and a qualified turbine engineer on site. Alignment, bolt tensioning and clearance records are the part of the job that decides whether the machine runs cleanly to the next interval or comes back in six months. This is specialist work and it should be scoped, witnessed and documented as such.
Condition monitoring earns its place here, and it is worth being precise about what it does. Vibration trending, performance monitoring and lube oil analysis will tell you that something is changing and often what class of problem it is. They will not measure coating thickness or residual creep, and they do not extend a published interval on their own. What they do is shorten the time between a fault starting and you knowing about it, which is a different and still valuable thing.
The same discipline applies across the rest of the train, which is why we handle it under rotating equipment services rather than treating the turbine in isolation. Plants running steam alongside gas should read the equivalent logic for steam turbine overhaul, where the damage mechanisms differ but the interval discipline does not.
For the formal framework, ISO 3977-9 sets out how reliability, availability and maintainability data and overhaul criteria should be exchanged between manufacturer and operator (ISO 3977-9:2024), and ISO 21789 covers the safety requirements governing how the work is carried out (ISO 21789:2022). Both are worth citing in a tender document because they give you a defensible basis for scope.
To put your unit’s actual factored hours against a costed outage plan, request a technical proposal.
Frequently Asked Questions
Are the 8,000, 24,000 and 48,000 hour figures fixed for every gas turbine?
No. They are typical for heavy duty industrial frames on natural gas at base load, and they are a starting point rather than a rule. Aeroderivative machines follow a different pattern, often with hot section refurbishment nearer 25,000 hours and full overhaul handled by module exchange. Always work from the OEM technical instruction for your specific model and serial number, then apply your own severity factors on top.
Can we run past a published inspection interval if the machine is performing well?
Performance is a weak indicator of hot section condition. A machine can hold output and heat rate while carrying advanced creep or coating loss on the buckets, because that damage shows up as a step failure rather than a gradual decline. Running past an interval is a commercial decision that moves risk from a planned outage to an unplanned one, and the cost difference is usually an order of magnitude. If it must be done, do it against a fresh borescope result and a written risk assessment, not a hunch.
How much do trips affect the inspection schedule?
Heavily. An emergency trip from base load is typically counted as 8 equivalent starts, and a trip from peak load can be counted at 20, because the hot section sees rapid uncontrolled thermal transients. A plant with frequent trips will reach its start based limit long before its hour based limit. Fixing the trip causes is normally far cheaper than absorbing the accelerated maintenance that follows.
What lead time should we allow for a hot gas path inspection?
Plan at least six months ahead for a hot gas path inspection, and closer to nine to twelve months for a major overhaul. The outage itself is two to three weeks for hot gas path work, but parts procurement, refurbishment turnaround and customs clearance dominate the timeline. Where components go abroad for repair, build in shipping in both directions and clearance at each end.