Safety top of the mind at Power Users’ Combined Conference – Combined Cycle Journal

Safety top of the mind at Power Users’ Combined Conference

The Power Users’ Mega Event—incorporating the annual conferences of the Combined Cycle (CCUG), Steam Turbine (STUG), Power Plant Controls (PPCUG), and Generator (GUG) Users Groups, plus the Low Carbon Peer Group—is only about three months away (August 28-31, Omni Atlanta Hotel at CNN).

Consider getting your travel request into management early so you don’t miss what many users believe is the industry’s most comprehensive conference/vendor fair and networking opportunity for supervisory personnel, engineers, and technicians involved in plant operations and maintenance.

Gas and steam turbines, generators, HRSGs, control systems, and emissions controls are all high-profile presentation/discussion topics on the agendas of the five groups. Recall that a ticket to any of the user-group meetings gives you access to all. Meals and vendor fair are joint activities.

Keep up on program developments in the coming weeks with a periodic visit to to review current agendas.

CCJ ONsite’s highlight reel from last summer’s meeting, which follows, offers the opportunity to evaluate the depth of content you can expect at this special event and assist in your decision-making.

The confluence, in one hotel in San Antonio, Tex, of knowledge, experience, and expertise on how to keep the nation’s aging gas-turbine-powered generating facilities operating in the face of shoestring budgets, supply-chain disruptions, and labor shortages, was perhaps unprecedented.

Over 350 users participated, with a slightly higher number of vendor representatives,

Critical condenser safety event

If you never thought a condenser could explode (as opposed to over-pressure), don’t feel bad. Neither did most of the attendees in the CCUG session listening to a representative from a major Texas utility explain how it happened at one of their combined-cycle plants. If you operate a plant with a “performance” fuel-gas heater (FGH) taking heat from the water/steam cycle (in this case from the intermediate-pressure circuit), you will most certainly want to review this presentation immediately and consider the recommendations arising from the utility’s fleet assessment of this situation.

Like most catastrophic (or potentially catastrophic) events, several unique factors had to align, as detailed in HRSG Forum, CCJ No. 72, p 42. Above all, the plant was in an abnormal outage during which the ST/G was forced out of service, and the GT/Gs were maintained in “ready” mode for the grid, meaning that fuel lines were at pressure up to the emergency stop valves. Other factors included, but were not limited to, a leaking FGH isolation valve; plugs in the tubing of the FGH shell-and-tube exchanger having fallen out; a delta P across the FGH pushing natural gas into the water/steam circuits, then through the drain lines terminating at the condenser; and others.

You have to review the referenced article to fully appreciate the details behind the factors which ultimately led to a buildup of natural gas in the condenser over an 11-day period to a percentage between the lower explosive limit (5%) and the upper explosive limit (17%).

When a welder struck an arc to replace a 1-in drain line on the condenser’s outside wall, an explosion occurred followed by a shock wave felt across the facility. The welder was not required to test for presence of combustibles because the hot work was outside the condenser.

Thankfully, no injuries occurred, no condenser tube leaks resulted, but six overpressure rupture disks on top of the condenser blew out and landed across the facility (one narrowly missing a worker), there was major damage to some structural steel inside the condenser, and the low-pressure turbine cover lifted six inches when bolting threads failed.

The bountiful list of after-event recommendations range from identifying all vessels where gas can accumulate to reassessing FGH design, especially the need for the bypass valves.

Catastrophic arc-flash event

Also at the CCUG, a representative from a 750-MW, non-utility combined-cycle plant in the Northeast reported on an arc-flash event with the 230-kV line into the plant, which resulted in a 10-in. hole in the ground when it hit below, and the loss of ac power to the plant. With no black-start capability, the relatively inexperienced crew onsite (and an operator in the control room who had “just qualified”) at the time had to get the emergency diesel/generator (EDG) online and synchronized, a process which should have taken three minutes but ended up taking 15.

The arc-flash event occurred when someone at the facility next door, a large warehouse operation, used a man-lift to replace a bulb on an outdoor light pole/fixture under the transmission line. It was discovered later that the neighbor firm had no plan/procedures in place for work near an energized line. Miraculously, the worker on the lift was not harmed. Nor was the person from the fire department who responded to the emergency and used the truck ladder to rescue the person on the lift. He performed this without knowing whether the line was energized or not. There was no collateral damage to the combined cycle.

Again, a confluence of factors had to line up for this event to occur. One was the fact that the normal power feed breaker did not open on loss of ac power, which meant that the EDG could not synch to the 480-V bus. The plant revised the procedure for EDG ops to include what to do if the normal power breaker does not open, and simplified what was previously a confusing EDG control scheme layout.

The light poles under the line have been removed, a physical barrier has been installed 20 ft off the centerline of the overhead line, and warning signs were hung along the fence line adjacent to the T line. All pre-job briefs now include a discussion of hazards associated with work near the 230-kV line.

Turning gear: Achilles heel?

Meanwhile, over at the STUG meeting, a utility expert noted that the steam turbine/generator’s turning gear (TG) could be a “pinch point” for ST/G reliability in plants that are starting and stopping more frequently to follow renewables. The utility had experienced a catastrophic failure of a TG motor caused by imbalance and a spare motor was not readily available.

It’s easy to forget that, in many cases, the TG probably was designed to operate perhaps 10 times a year, but under future operating scenarios, this person noted, that could increase to 500 or more (yes, multiple starts per day). Having the requisite spare parts in inventory or readily accessible is advisable, or perhaps even a motor in stock that could fit several different units. Also good to distinguish the number of hours the TG operates versus the unit itself and plan/adjust maintenance and spares accordingly.

The presentation slides at the STUG conference archives are replete with descriptions of different types of TG units and drive motors, photos of failure mechanisms, and recommendations for safety, spares strategy, and inspection procedures and frequencies. Also, you can dive a little deeper here in CCJ.

Control-system supply chain

Attendees in the PPCUG room wrestled with serious supply-chain challenges. Among them: Extending the use of processors slated for obsolescence because replacements are not available, “allocations” (read, rationing) of CPUs (central processing units) for specific families of controllers, lead times which have been extended by 50% to 100% since 2019 for many components and systems, and plants having to postpone and reschedule control system upgrades and other work, with suitable incentives and discounts offered, to ease the pressure on OEMs.

Thankfully, these issues have caused one control-system supplier to change its procurement system which the OEM presenter acknowledged was “not that sophisticated.” For one thing, they relied on too many single-source suppliers, one of which, in another admission, was their own company. Today, the OEM has visibility into its sub- and sub-sub supplier network, or what he termed “digital surveillance” of the supply chain, and could more appropriately forecast delivery times and/or problems.

Generally, control-system specialists expect these challenges to last at least another 18 to 24 months.


The Power Users highlights reel also included the following:

  • Owners are now seriously studying the impact on performance of extracting significant quantities of low-pressure steam for a carbon-capture process on the premises.
  • A utility operator said they were entering a “no man’s land” with respect to the hours some of their units were running. “How do we instrument these assets for safety and reliability and feel better” about operating them, he asked?
  • Cold-weather action items are tracked and managed by one utility’s power operations center, a centralized M&D facility, serving most of the assets in the fleet, as regulators like Ercot and NERC issue new winterization rules and standards.
  • Rupture and repair of a low-pressure crossover bellows on an ST/G with over 110,000 service hours at time of failure was examined by one utility STUG presenter, followed by another from a separate utility plant which experienced the same failure.
  • Steam-turbine valve maintenance is being neglected at too many plants, said one consultant. Contrary to popular belief, grit blasting does not remove oxides, which are responsible for 80% of valve sticking problems.
  • The travails of designing and periodically testing (twice annually) a black-start plant with an 850-Vdc, 13.7-MW, 3.4-MWh battery unit starting a single GT/G in California was discussed by a major non-utility owner/operator.
  • A prominent Texas utility reviewed seven separate case studies from the last five years of L-0 (last stage) steam-turbine blading, each example a different combination of OEM, blade length, type of plant, failure mechanisms, root causes, etc. Generally, L-0 blades are a high risk and potentially impactful component in the ST/G, he said, and OEMs have issued several service bulletins around them. Often, there are no operating indications of an issue before an event occurs.
  • An OEM updated the GUG audience on a new robotic wedging technology designed to re-tighten wedges faster and without wedge removal but does require a “rotor out” outage and about a shift’s worth of time to install.
  • Another ST/G OEM, in a STUG session dedicated to recent service bulletins and top issues, said his firm is now recommending that all ST/G units undergo annual last-stage blade inspections and that they are discovering “numerous and surprising” indications in critical locations of HP and IP shells in units 15 to 20 years old.
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