Coal, Gas, O&M

Insuring Best Practices

Issue 6 and Volume 109.

Insurance companies expect power plant owners to follow preventive maintenance best practices to limit risk exposure. Implementing such practices for critical components not only keeps insurance premiums down, but also avoids costly downtime and equipment failure.

By implementing best practices for preventive maintenance, power plants can head off equipment failure, avoid costly downtime and reduce corrective maintenance costs. Effective preventive maintenance is also an essential tool in keeping insurance rates down. This article discusses several critical power plant components and the operating and maintenance practices that insurance companies expect to be implemented to reduce their risk exposure.

Because of their use in the majority of large-scale power plants, steam turbines are the focus of this article, spanning lube oil analysis, high-energy piping, vibration monitoring and turbine overhauls, with particular emphasis on the turbine overspeed testing process.

A proper steam turbine maintenance program will include all OEM recommendations and suggestions specific to the turbines at each insured location. How these recommendations are implemented is very important to the turbines’ well being. Not fulfilling OEM recommendations, particularly the critical ones, can affect the insurability of a turbine and trigger unpleasant insurance penalties as well.

Lube Oil Analysis

Most insurance carriers are convinced that oil analysis is a vital predictive and preventive maintenance tool and expect to see it in use at its insured locations. Periodic turbine oil analysis may be performed monthly or quarterly. Component wear can be verified by the presence of certain contaminants in the oil, such as wear metals like copper, chrome, aluminum, iron, nickel, lead and tin.


Typical steam turbine overspeed trip device.
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Most bearing or gear failures occur after their condition has slowly deteriorated over the course of months or even years. Quarterly sampling can provide a more subtle indication of oil or component deterioration, or the slow beginning of oil contamination. Long-term monitoring of oil condition (over several months or quarters) can reveal improper repair or maintenance practices, such as the failure to conduct effective system flushes after repairs, or the improper handling of lubricants, which can introduce dirt or even water to the oil.

High Energy Piping

All major insurance carriers require periodic piping inspection. A program that incorporates the routine inspection (usually during major overhauls) and characterization of anomalies in the piping welds is necessary for the piping to and from all the turbine valves and other components. Responsibility for inspection of this piping lies with the turbine maintenance/inspection group or the boiler group.

Vibration Monitoring and Phase Angle Checks

State-of-the-art turbine bearing vibration monitoring systems should be installed and operating properly. Vibration monitoring is a particularly important condition monitoring tool, considering the extended overhaul intervals now in vogue (see sidebar), and its use is expected by insurers to ameliorate their risk exposure. Phase angle monitoring of the bearing vibrations is also an important component of this condition monitoring and should be incorporated into a good vibration monitoring program.

Bearing vibrations can be monitored using one of several methods. Displacement probes measure shaft movement directly. Some models contact the shaft directly, using shaft riders; others are non-contacting types, called proximity probes. Conversely, velocity pick-ups do not measure shaft displacement directly, but quantify the energy transferred from the shaft to the bearing housing. To measure absolute shaft vibration, a proximity probe and a velocity pick-up are generally installed together at the bearing housing. This arrangement provides both absolute shaft vibration levels as well as vibrations relative to the bearing measurement. Displacement probes are usually used on turbines and generators that have a high rotor-to-casing weight ratio, or on turbine generators greater than 100 MW. Rotating equipment that has a high casing-to-rotor weight ratio can use velocity pick-ups with success.

Overspeed Trip Testing

To guard against catastrophic failure from an uncontrolled overspeed by a steam turbine and its driven equipment, protection is provided in the turbine trip system to close the steam valves.

Conducting the annual overspeed trip test on steam turbines is, and will continue to be, a contentious issue with insurance carriers. With overhaul intervals and the time between routine boiler outages increasing, scheduling the steam turbine’s overspeed test may be extended or overlooked. Specific concerns with the mechanical integrity of the turbine or generator field may also engender reluctance to conduct the test.

Generally, overspeed prevention techniques have centered on the overspeed trip mechanism. However, the overspeed trip checks should be viewed as a system verification that comprises more than the mechanical or electronic overspeed trip device. Many uncontrolled overspeed events are the result of valves failing to close, even when the overspeed trip device operates. Further, nearly all uncontrolled overspeed failures are catastrophic, resulting in blade failures, shaft breakage and retaining ring bursts.

Overspeed protection should be a combination of the following:

• Proper functioning of mechanical or electronic overspeed trip mechanisms and system

• Positive closing of the main steam and control valves

• Positive closing of the reheat inlet valves

• Proper functioning of the extraction system non-return valves

• Proper functioning of the reverse power trip on the generator.

Mechanical/Electronic Trip Mechanism

The mechanical or electronic trip mechanism is the last line of defense for protecting the steam turbine and driven object. To reach the trip point for this device, all other means of controlling the energy input into the turbine have already operated or not functioned. If the valves and devices work properly, the likelihood of the turbine going to severe overspeed is much less. If the valves do not fully shut, and the other devices do not work properly, even though the trip mechanism actuates, the turbine may still overspeed because the steam source is still present and uncontained.

Most insurance carriers require that the mechanical device be tested annually by an actual overspeed of the turbine. In some cases, however, insurance carriers will allow up to 18 months between tests to accommodate extended outage schedules. The simulated electronic trip devices can be tested more frequently, as often as monthly, because they have no direct effect on the steam turbine’s operation.

Some owners have resisted annual mechanical tests because they can place additional stresses on steam turbine and/or generator components, such as last-row turbine blades or generator end turns. Most carriers believe that the proper operation of the overspeed devices revealed by testing is more important than whatever minimal stress the turbine components may experience from the test. If there is concern that a specific component may be damaged by the test, this can raise a “flag” to the insurance company that there is higher risk of catastrophic loss. This raised flag could lead to restricted coverage of the unit or other insurance penalties.

When the mechanical device is tested, all automatic turbine steam valve operation to the turbine should be verified by visual inspection. All requisite alarms and indicators should also be observed for proper operation.


Retaining ring burst due to a steam turbine overspeed event.
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Some original equipment manufacturers (OEMs) have relaxed their requirements for testing overspeed trip devices. In direct contrast with the insurance carriers, at least one OEM has allowed the testing interval of the overspeed trip device to be extended to the unit’s major inspections. For some units, this could mean more than 10 years between tests.

Main Steam and Control Valves

Unfortunately, the OEMs provide differing arrangements for admitting steam to the turbine and the ability to test the valves is sometimes compromised. The desired testing method is to stroke a valve from fully open to closed, thus checking the valve’s capability to operate through its entire range. Build-up on the valve stem, excessive stem run-out, deposits and deteriorated components can prevent the valve from operating properly or not at all.

These valves should be exercised on a weekly basis, at a minimum. It is common, however, for these valves to be tested daily to deter a valve from sticking in a fixed position and to verify each valve’s ability to fully shut.

Reheat Inlet Valves

Even after the main steam stops and control valves have completely closed, steam flows through the boiler’s reheat section as the high-pressure steam turbine exhausts to the cold reheat piping. The energy contained in the reheat section can cause the steam turbine to overspeed if the generator output breaker has been opened. Valve testing in accord with the OEM recommendations is necessary or, in some cases, the insurance company’s more restrictive recommendations (such as fully stroking the valve) may be required.

Like the main steam and control valves, the desired testing method is to stroke the valve from fully open to closed, ensuring that the valve operates through its entire range. Build-up on the valve stem, excessive stem run-out and deteriorated components can prevent the valve from operating properly.

These valves should be exercised on a weekly basis, at a minimum. It is common, however, for these valves to be tested daily to deter a valve from sticking in a fixed position and to verify each valve’s ability to fully shut.

Extraction Steam Non-Return Valves

Non-return or bleeder trip valves are specifically installed to prevent the energy contained in the feedwater heaters from backing up into the steam turbine, potentially causing an overspeed trip. Testing of these valves should be conducted in accordance with OEM recommendations. These non-return, pneumatic-type, flapper valves should be tested on a daily basis. For these valves, proper operation is more important than whatever minimal wear they may experience from the test.

There may be some power level restrictions with the higher energy feedwater heaters. The extraction line drains on the turbine side of a check valve or stop valve are starting drains and must stop moisture from accumulating in the line and backing up into the turbine. These starting drains should be power operated and should be shut when not at low load and with the heater in service. The drain valve in the lowest pressure extraction line may be shut when operating above 30 percent load and the drains in all the other extraction lines may be shut above 15 percent load. The steam traps in these lines are considered inadequate protection and should only be used in parallel with the extraction line drain valve.

When the non-return valve is tested, it is important to observe the valve shaft’s physical movement. During valve tests, the flappers will move only slightly, perhaps only a few degrees, but this is enough to ensure proper function and does not interfere in any way with normal operations. In some cases, attention is directed only to the actuator, or worse, only to the actuation of the test valve. The non-return valve’s physical location may require two operators to conduct the test. Placing paint marks on the shaft or on the end of the shaft can make it easier to observe shaft movement.

Generator Reverse Power Trip

Most OEMs require that a generator reverse power trip be installed to prevent an overspeed of the turbine generator when the steam turbine trips. Leaving the generator output breaker closed as the steam turbine energy is exhausted and then tripping the generator by the reverse power relay will prevent a potentially catastrophic turbine overspeed and allows a more controlled unit shutdown during a boiler or turbine trip. During a generator trip, however, the functioning of the overspeed trip devices becomes more critical and attention to the timing of the valves shutting completely is even more important. Most insurance carriers require an annual test and calibration of the generator reverse power trip. p

Authors –

James R. Peterson is president of High Energy Consulting, LLC. After more than 23 years with HSB, mostly as a B&M Power Generation Specialist inspecting power plants of every variety in the United States and Canada, Peterson started a consulting company to continue this work. He has a BA degree in print journalism from the University of Montana and engineering course work at Iowa State University. Peterson also spent eight years in the U.S. Nuclear Navy as a submarine nuclear operator, supervisor and instructor at the A1W prototype, and as a nuclear-qualified Navy scuba diver.

T. Keith Schafer, Jr. is a vice president with Marsh Risk Consulting. He has more than 35 years of experience in power generation, in the Navy Nuclear Power Program as an operator, supervisor and instructor, and with Hartford Steam Boiler as a senior utility specialist at numerous power facilities around the world. Schafer currently works with Marsh Risk Consulting providing services to various utilities in the United States and abroad.

The Overhaul Interval Debate

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Setting a reasonable maintenance period while maintaining the availability, reliability and insurability of a critical generation asset is a necessary but difficult task. Overhauls are generally a contentious topic, especially when applying overhaul guidelines to equipment that is infrequently operated, such as prime movers in emergency, cold standby or peaking service, or units about to be retired or sold

Overhaul frequencies for power generating equipment have historically been set by the OEMs. These calendar or operating hour-based intervals have worked well, provided the equipment to be serviced is baseloaded, operated two shifts/day or in peaking service that approximates either of these operating modes. For generating units that are in peaking service or that operate less than 1,000 hours/year, however, these OEM guidelines do not provide realistic maintenance targets.

Service class differentiation can be used to explain the operating modes of generating equipment regarding component maintenance planning. Service Class 2 refers to units that are in peaking, standby and/or emergency service that operate less than 1,000 hours/year. For example, a unit that operates 2 to 3 hours/day in peaking service would accumulate about 1,000 hours/year and would fit into this class. Service Class 1 encompasses unit components in all other operating modes.

Service Class 2

For peaking, standby and emergency service units that operate less than 1,000 hours/year, dismantled inspection frequency is a controversial subject with insurers. Each insurer determines peaking service overhaul intervals using similar engineering considerations, but each may reach differing conclusions depending on its loss history, market tolerance, or even its loss ratios or profitability. In some cases the carrier may opt out of the risk using reinsurance.

Equipment owners view dismantled inspections of peaking or standby units from a more pragmatic perspective. Though budget considerations will likely be involved, the owners are most concerned with reliability and availability in the event a unit is returned to operation described under Service Class 1.

OEM time guidelines for dismantled inspection frequencies will be exceeded if they are followed for units in this service. There are cases of units that operate only two or three hours a month and, even with severe penalties for cold starts, could go 50 years or more without approaching the OEM-recommended overhaul frequencies. This is particularly true with emergency diesel generators. So, what is a reasonable way to keep the equipment available and properly maintained within a practical overhaul period?

If each unit is evaluated on a case-by-case basis, its operating and maintenance history can be compared to industry standards and best practices. Several factors must be considered when assessing the viability of an extended turbine overhaul interval (see table).
Satisfying the insurance carrier should also be a consideration. If the above can be accomplished using good procedures and documentation, the carrier’s concerns can be met. Nevertheless, the inconsistencies between insurer’s standards, guidelines and even personalities can complicate this process. Using sound engineering judgment and principles in critical component operations and maintenance should be the most important owner concerns.