Users compare notes
The 2025 Legacy Turbine Users Group, consisting of tracks for the GEV 7E, 6B, and 5 fleets, in Minneapolis again demonstrated why user-group meetings still matter for mature fleets. LTUG is not where owner/operators go to hear that legacy machines are old. Everyone in the room already knows that. They go to compare notes on which components are aging out gracefully, which ones are becoming outage traps, and where the most practical fixes are coming from users, independent suppliers, owner’s engineers, or the OEM.
A few themes cut across the week. First, cycling duty is still changing the failure map for legacy machines. Starts, part-load operation, and dispatch volatility continue to show up in vane looseness, combustion instability, accessory-system wear, and inspection urgency. Second, exhaust-section degradation is no longer a side issue. Diffusers, flex seals, inner barrels, and associated structural cracking are moving toward the center of many fleet life-extension decisions. Third, users are becoming more selective about where they accept OEM framing and where they want alternate repair or replacement paths. And fourth, everyone is trying to make smarter choices about what to repair, what to upgrade, and what to stop nursing along.
Fleet housekeeping drives reliability
The Frame 5 and 6B user material focused on maintenance planning, peaker operation, auxiliaries, combustion hardware, compressor sections, control systems, generators, safety, and turbine hardware. That may sound basic. It is not. Mature fleets are often lost not because operators lack a strategic vision, but because the everyday systems surrounding the turbine stop getting disciplined attention.
The maintenance-planning and peaker-operation material made that point clearly. Users emphasized tracking and projections, interval drivers, outage timing, repair planning, spares, shop-space constraints, capital-part replacement planning, and life-cycle decisions for controls, wiring, casings, ducting, and auxiliaries. They also highlighted familiar peaker-specific pain points: oil circulation, ratchet operation, cranking performance, FSNL behavior, synchronization and low-load operation, and how all of that changes maintenance scope and timing.
That framing is important for plant managers because peaking service has a way of disguising reliability erosion. A unit that runs fewer hours can appear healthy while accumulating starts-related wear, accessory-system distress, and control-system fragility. LTUG’s user discussions suggested that several fleets are now treating peaker maintenance as its own discipline rather than as a lighter version of baseload maintenance. That is the right move. Ratchets, starting systems, oil systems, and low-load behavior deserve their own review cycle when dispatch patterns change.
The auxiliaries session reinforced the same point at component level. Users worked through starters, torque converters, clutches, ratchet systems, accessory gears, load gears, lube-oil systems, oil-mist separators, hydraulic systems, and cooling/ventilation hardware. Nothing in that list is glamorous, but nearly every item can delay a start, complicate an outage, or trigger a trip if it is allowed to drift into the background. Mature fleets tend to accumulate tribal workarounds in these systems. User groups remain one of the few places where those workarounds get compared openly.
The combustion session also stayed grounded in hardware realities: fuel nozzles, liners, flow sleeves, transition pieces, crossfire tubes, ignitors, flame eyes, and associated piping and cans. Frame 5/6B fleets are increasingly being asked to do work they were not optimized for decades ago—more starts, wider operating windows, and, in some cases, tougher emissions or fuel-flexibility demands. Combustion sections therefore sit at the intersection of reliability, compliance, and life-cycle spending.
The compressor, controls, and generator sessions showed a similar pattern. Users centered their discussions on inlet air systems, IGVs, rotor and stator issues, extraction points, online/offline washing, control-system support and upgrades, gas-valve behavior, DLN tuning, exciter hardware, TEWAC leak detection, and general generator condition. None of these are new topics. But the recurring need to revisit them is itself a signal: the fleets that are still performing are not assuming that “basic” systems will take care of themselves.
The safety session, covering fire suppression, halon, CO2, water mist, heat detection, hazardous-gas analyzers, lockout/tagout, confined-space entry, turbine compartments, and filter-house considerations, added a useful reminder. As legacy fleets age, maintenance and reliability decisions increasingly overlap with personnel exposure. Accessibility, degraded housings, aging fire systems, and outage-work density all raise the penalty for a casual safety culture. In practical terms, the reliability discussion is not separable from execution discipline.
Taken together, the Frame 5/6B user presentations pointed to one broad conclusion: owner/operators still have substantial leverage over reliability outcomes through routine planning and execution.
Frame 5 and 6B vendor presentations
If the user presentations emphasized day-to-day operating reality, the Frame 5/6B vendor presentations emphasized optionality. Controls specialists, rotor-life-extension providers, exhaust-system repair firms, winding manufacturers, and combustion-upgrade vendors all made the case that there are still economically rational pathways to keep legacy machines relevant. The question for readers is not whether those pathways exist. It is which ones are grounded in the condition of a given asset and which ones are being sold as broadly applicable solutions.
AP4’s controls-reliability assessment talk framed one end of that market. The presentation argued that routine panel cleanup, voltage checks, alarm review, and junction-box inspection are not enough by themselves. The more important questions involve decision matrices by control platform, EEPROM strategy, human-machine-interface support, technical information letter applicability, multi-unit audit exposure, single points of failure, spares, ground-fault exposure, diagnostics, and calibration discipline. The case examples were useful because they showed how mundane-seeming logic or hardware conditions can create hidden risk. One example involved lube-oil heaters and a welded main contactor; the corrective action was not just replacing hardware but eliminating a logic dependency and revising LOTO practices. Another example challenged an operator’s assumption that unstable exhaust temperature was necessarily a combustion problem. The larger message was that controls health assessments need to be framed as trip avoidance and latent-risk discovery, not as housekeeping.
EthosEnergy approached the conference from the rotor side, presenting data-driven risk assessment for life extension and reframing rotor limits as an evaluation problem rather than an arbitrary end-of-life boundary. That is consistent with where much of the aftermarket is moving: away from simplistic age-based replacement arguments and toward condition-based life extension backed by engineering review. For owner/operators, the attraction is obvious. New-machine supply remains constrained, capital budgets are finite, and some legacy assets still make money. But the discipline required is equally obvious: life-extension decisions are only as credible as the inspection basis, the operating history, and the assumptions behind the risk model.
Exhaust and combustion hardware. Gas Path Solutions reviewed MS5000 and MS6001 exhaust systems and highlighted typical components—expansion joints, covers, plenums, diffusers, and exhaust frames—before drilling into known fleet issues. Expect increasing repair costs over time, material degradation, repairs not achieving desired operating intervals, cooling-air loss, and cracking in multiple locations, including horizontal parting joints, outer diffusers, aft diffusers, and turning vanes. That is a serious message because exhaust problems tend to present as “repairable” right up until they become schedule and scope problems.
BFI Automation’s flame-monitoring pitch was simple: legacy UV-based flame-monitoring hardware brings non-fail-safe behavior, limited repairability, unpredictable expiration, and replacement constraints. The alternative on offer was optical hardware with self-checking capability, trendable output, and field-replaceable electronics. Readers should recognize both sides of that story. The vendor claim may be valid. But the more durable takeaway is that flame monitoring has become an operational reliability issue, not just an instrumentation detail, especially where false trips or liquid-fuel service are involved.
The PSM FlameSheet presentation expanded the conversation from simple repair into performance repositioning. Here, the most notable claims involved low-NOx combustion over a wider operating range, sub-9-ppm NOx and CO performance, stable operation down to 27% load in one example, and use of refinery off-gas or hydrogen-containing fuels. The strategic implication is real: some legacy fleets are being asked to do a more flexible, fuel-diverse job than their original hardware packages support. But users should evaluate such offerings with care. Emissions, operating window, and fuel-flexibility claims often depend on application-specific constraints, tuning margin, and site fuel composition.
National Electric Coil’s Tyler Gaerke made a different point in his stator-winding presentation: replacement quality matters as much as availability. As rewinds and life-extension projects grow more common, owner/operators are navigating supply-chain pressure and a widening quality-expectation gap. That is a reminder that “replace” is not automatically the conservative choice. On older fleets, replacement hardware introduces its own risk if quality systems, design assumptions, or inspection criteria are weak.
7EA end users talk shop
The 7EA user presentations had a slightly different character. They read less like broad roundtables and more like snapshots of the actual questions plants are carrying into outages and troubleshooting sessions right now. That makes them especially useful.
One cluster of discussions centered on inlet cooling and performance management. A user asked whether anyone was operating evaporative coolers below base load on 7EA units because the OEM had set the equipment permissive at base load even though the plant was rarely there. The responses suggested that at least some peers still operate evaporative coolers only at base load. A related discussion on inlet fogging reported that one 7FA site was seeing a 10- to 15-MW increase during summer operation and that one owner had fogging systems on eight 7EA units, with decent performance but significant maintenance demands in below-freezing weather.
Another cluster involved combustion and flame-detection problems. One user described repeated flameouts at 10 to 15 MW shortly after synch. Gas flow, bleed valves, and IGVs looked acceptable; compressor discharge, load, and exhaust temperature then fell off until flameout. Peer suggestions included checking rebuilt bleed valves for incorrect installation, checking inlet filters, and verifying IGV angle physically rather than trusting indication. The eventual cause was neither an obscure compressor defect nor a hidden plenum obstruction. It was a malfunctioning NOx water-flow meter, likely damaged by a lightning event, reading no flow and effectively drowning the flame.
Flame monitoring surfaced again in a separate exchange on optical flame-detector fouling during liquid-fuel operation. One respondent pointed to condensation issues with water-cooled detectors and said air purging resolved the problem. Another reported replacing OEM water-cooled scanners with alternate hardware and eliminating the issue.
The exhaust section generated some of the strongest discussion. One user was planning to replace the exhaust diffuser on a 2001 7EA because of excessive cracking and was looking for lessons learned. Another reported extensive vertical cracking around the inner barrel, had the material evaluated metallurgically, and found sigma phase. That finding matters because when sigma phase develops, the material becomes more brittle and more susceptible to thermal and mechanical fatigue cracking with continued exposure. The presentation further distinguished between a traditional one-piece replacement diffuser, which requires stub-shaft removal between turbine and generator, and a split-design alternative intended to simplify installation. User responses indicated that some plants are still living with annual inspection and weld-repair cycles, and that related failures such as flex-plate separation and stack-silencer distress may be linked to diffuser degradation.
Additional user material reinforced the sense of a fleet managing through component-specific distress. One plant described internal flex seals downstream of third-stage buckets shifting badly enough to create an opening approaching 40 in. at the 11 to 12 o’clock position, with the seal stuck in the upper exhaust-case groove and the user trying to avoid a window-weld process. Another described a refurbished torque converter that would not break away at startup despite apparent oil pressure and normal cranking-motor behavior, causing the output shaft to turn only about 180 deg before tripping. Yet another site saw a mid-run step change in two exhaust thermocouples, roughly 100F down, followed by a sharp CO increase and a small generation loss of about 0.5 to 1 MW, without obvious leaks or visible borescope evidence.
7EA vendor presentations
The 7EA vendor presentations expanded on many of the same issues but with a sharper emphasis on inspection methodology, repair pathway, and upgrade economics.
AGT Services’ generator-testing presentation was one of the clearest examples of a vendor message aligning closely with user needs. The central argument from Jamie Clark was that experienced generator specialists remain indispensable; dirt tells a story and should not be cleaned away before inspection; speed does not equal quality; and extending inspection intervals is proving detrimental to generator reliability because newer replacement assets often have less margin, less mass per MW, and cheaper materials. The detailed list of what to inspect—end-winding support systems, wedge systems, gas-gap baffle studs, stator core tightness, vent-duct blockage, rotor cleanliness, arcing, tooth-tip hot spots, retaining-ring condition, collector rings, fan damage, and copper dusting—reads like a reminder that generator failures still reward fundamentals. For managers deciding whether to save outage time on inspection scope, the message was blunt: shortcuts are a false economy.
Entrust’s borescope-report interpretation session made a similar argument for the turbine itself. The presentation stressed that borescope value depends on inspection quality, access, interval selection, and correct interpretation of what is seen. It identified typical failure modes across the inlet, compressor, combustion, turbine, and exhaust sections: IGV deposits and erosion, IGV cracking and bushing migration, forward-casing distortion, first-stage erosion and cracking, combustion-liner bulging, transition-piece cracking, nozzle cracking, tip lifting, knife-edge seal damage, strut-heat-shield cracking, inner/outer barrel cracking and separation, flex-seal cracking, and broken thermocouples. One practical example described mitigating risk through borescope inspections every 25 starts to bridge a unit to a planned combustion inspection. That is the kind of operating decision owner/operators have to make constantly, using inspection frequency as a risk-management tool, not just as a compliance interval.
CTTS’s compressor stator-vane looseness presentation was another standout because it tied changing dispatch duty directly to mechanical consequences. Starts and part-load operation were cited as drivers of increasing looseness. The presentation challenged the sufficiency of the OEM “big foot” approach, described a pinning solution installed on six units over the past two years, and warned that casing cracks and escalating repair costs can follow if looseness is ignored. It also emphasized that borescope inspection can detect some issues, but that upper-casing removal is often key to proper risk assessment. Whether readers agree with the vendor’s preferred repair solution or not, the core message is credible: stator-vane looseness is a condition that can move from nuisance to structural risk if deferred too long.
IPS focused on exhaust-frame assemblies and identified a fleet burdened by rising repair costs, material degradation, cooling-air loss, parting-joint separation, aft-diffuser cracking, turning-vane cracking, and inner-barrel circumferential cracking. The presentation explicitly posed the central owner/operator questions: Has a detailed inspection been performed? How long has crack repair been going on? Are you already planning an internal alignment? Are you in a position to replace, refurbish, or continue repairing? Those are the right questions, and they mirror what users were already discussing in their own sessions.
MD&A’s lifetime-extension presentation approached hot-gas-path decisions with a repair-process lens. The extracted text points to specialized inspection, phase-array and x-ray evaluation, CT-scanning support during repair development, process controls, and examples of first-nozzle and combustor-liner repairs involving crack removal, welding, brazing, and coating restoration. The presentation also highlighted the economic logic behind repair versus replacement and repeatedly tied repair credibility to inspection depth and process control. Again, readers should separate marketing from usable takeaway. The important lesson is not that one shop has every answer. It is that HGP life-extension decisions should be built on inspection capability, defect detectability, and known process controls—not on generic price comparisons.
Crown Electric’s Bruce Hack went “all-in” for his breaker retrofit presentation to emphasize that not all legacy-fleet problems are inside the turbine. Main bus duct and generator circuit breakers were described as weak links nearing or at end of life, with cooling challenges and under-rated legacy hardware creating risk. Turnkey retrofill replacement of older breaker designs may sound like an electrical niche, but it fits the conference pattern: more plants are discovering that the practical limit on asset life is often set by support systems, not just the turbine rotor.
Finally, several presentations addressed broader operating context. The owner’s-engineer talk from Gulf Turbine Services emphasized quality control, attrition mitigation, and project-management support. MD&A’s “Safety Differently” presentation argued that safety and productivity can reinforce one another if organizations learn proactively rather than trying to “change behavior” by slogan.
What’s next?
Three practical conclusions emerged from LTUG 2025 that will undoubtedly continue this year and beyond.
First, inspection quality is becoming the dividing line between rational life extension and wishful thinking. That applies to generators, exhaust systems, borescopes, controls, and compressor hardware. Plants that know the condition of their assets in detail still have options. Plants relying on old assumptions are more likely to discover their limits in the middle of an outage.
Second, users should treat exhaust systems and associated structural hardware as strategic assets, not as endless repair candidates. Diffusers, inner barrels, flex seals, and turning vanes are showing up repeatedly in both user concerns and vendor offerings. Once cracking is persistent, metallurgical degradation is confirmed, or repairs stop lasting to the desired interval, the decision framework has to widen from repair procedure to fleet strategy.
Third, dispatch reality is now inseparable from hardware strategy. Peaking duty, low-load operation, wider cycling, fuel flexibility, and emissions pressure are affecting how legacy machines fail and what upgrades are worth considering. LTUG 2025 made clear that many of the best responses are still practical ones: tighter maintenance planning, better condition assessment, smarter control-system audits, more disciplined troubleshooting, and a willingness to challenge inherited limits when the operating profile has changed. CCJ
