Five reasons emergency generators fail when you need them

Here are five common reasons why generators fail

By John Yoon May 31, 2022
Courtesy: McGuire Engineers


Learning Objectives

  • Examine five common reasons for generator system failure.
  • Review NFPA 110 maintenance recommendations as they relate to emergency power supply system reliability.
  • Learn about generator sizing and how it affects performance.

Engineers tend to focus on prescriptive design solutions for mission critical and life safety generator applications. Often the guiding concept is that adding capacity and complexity to the design helps ensure reliability. However, the devil is in the details. Real-world generator system reliability is often dictated by seemingly simple, mundane items that are often overlooked.

It’s reasonable to expect that a properly installed generator will function perfectly on Day One, but it should also be noted that its useful service life will often extend well beyond 25 years. In addition, that generator is only one component of a larger emergency power supply system. Failure of any individual part of that system could compromise the overall performance and reliability of that system. Given that extended service life, the logical question for any engineer is, what parts of that system will become vulnerable as the system ages and how can the associated risks be mitigated?

NFPA 110: Standard for Emergency and Standby Power Systems is the most applicable standard in this regard. NFPA 110 addresses installation, testing and (most importantly) ongoing maintenance requirements for the EPSS. The issues that are examined in this article echo those identified within NFPA 110 and consist mostly of simple items that have outsized consequences if not properly addressed.

Figure 1: Interior of a more than 30-year-old automatic transfer switch. Proper maintenance and testing of automatic transfer switches is often neglected and can lead to a generator system failure. Courtesy: McGuire Engineers

Here are five common reasons why generators fail, with additional information available in the next issue:

1. Automatic transfer switch failed to properly transfer or signal the generator to start

UL 1008 “Standard for Safety Transfer Switch Equipment” details rigorous testing requirements to ensure that automatic transfer switches are reliable during normal operation. The UL 1008 tests include verification of the ability of an ATS to operate under abnormal conditions (withstand fault current, close into a faulted circuit, survive overvoltage events, etc.)

The UL standard also includes an endurance test requirement. This test has two different sets of criteria depending on if the ATS is rated for “total system load” or a less stringent “optional loads” rating. Only total system load rated ATSs are suitable for life safety and legal required loads. As such, the vast majority of ATSs used in commercial construction projects are rated for total system load.

The more stringent total system load test is performed both with and without current for anywhere from 3,000 to 6,000 transfer cycles. The quantity of cycles performed under each condition is dictated by the rated ampacity of the ATS. Where tested under current, half of those cycles must be performed at 100% rated load and the other half at 200% rated load. Real-world operating conditions never approach this UL severe testing criteria.

The severity of UL testing requirements compared to normal operating conditions would suggest that ATS longevity shouldn’t be a problem. NFPA 110 ATS monthly functional testing and annual maintenance recommendations are also extensive (see 8.4.6 and Appendix section A.8.3.4). Those recommendations include one major maintenance and three quarterly inspections per year. This testing in combination with the UL listing requirements should ensure a reliable system.

However, ATS related issues still cause genset starting issues. The reason isn’t that the NFPA 110 ATS maintenance requirements aren’t tough enough. The reason is that the recommended maintenance and testing is frequently skipped.

There is a well-founded fear that if there is a problem during functional testing and maintenance that it could potentially cause the downstream critical load to be dropped. However, this logic is flawed in that if ATS maintenance is not performed, any potential issues with the ATS will not show up until there is a critical need for generator power. These issues could be any number of items: the transfer mechanism seizing due to lack of lubrication/contamination, loose conductor terminals causing arcing, faults in generator start circuit wiring, etc.

The temptation is to specify complex devices such as an isolation bypass type ATS to allow for maintenance while the system is energized. However, what if the project cannot bear the associated cost and complexity? For most clients, other solutions are required. While risks associated with testing cannot be fully eliminated, they can be mitigated with proper planning.

This lesson can be learned from the data center industry, where methods of procedure (known as MOP) are commonly used to help identify and manage risk associated with maintenance on mission critical systems. A MOP is a highly choreographed step-by-step sequences of actions to be performed by maintenance personnel. By clearly defining actions and expected outcomes from each action, critical interdependences are more likely to be identified and the appropriate emergency procedures documented ahead of time rather than trying to make them up in the heat of the moment if something goes wrong during testing.

2. Generator has inadequate ventilation/cooling

The thermal efficiency of a typical diesel generator is around 40%. As such, a significant amount of energy from the fuel is rejected as waste heat without being converted into electricity. Proper management of that waste heat is a critical consideration in any generator system design. The generator’s capacity could be derated or it could fail entirely if adequate cooling isn’t provided.

The amount of airflow required for properly dissipating heat from the generator’s radiator is typically on the order of 15 to 20 times that required for combustion. And in most cases, the radiator mounted fan is typically only capable of 0.5 inches of static pressure. Those fans are generally incapable of pushing air through anything other than a shallow exhaust plenum and louvers. Correspondingly, NFPA 110 section requires that the discharge duct at the radiator outlet have a maximum static restriction of 125 Pa (0.5 inches of water column). This can come as a shock to engineers designing their first generator room.

Even with this requirement, many generator room ventilation designs are often marginal. Unfortunately, ventilation/cooling problems typically don’t crop up until the generator is run under heavy load. Monthly exercising that runs the generator without load typically doesn’t stress the generator’s cooling system nearly enough to uncover these issues.

Regular load bank testing at 100% of generator nameplate rating is recommended for identifying cooling system problems. Problems that crop up as the EPSS ages, like loose or corroded ventilation damper linkages that keep the damper from fully opening, should become obvious when load bank testing is performed. NFPA 110 section requires that the coolant temperature during load bank testing stabilize at a constant value relative to ambient outdoor temperature at least 30 minutes before the completion of a two-hour full load test. Unstable coolant temperature is a clear indicator that something is wrong with the generator’s cooling system.

Figure 2: This 1,500-kilowatt diesel generator is located within an unconditioned underground vault with limited access. Proper clearance and access are important in facilitating maintenance activities. Courtesy: McGuire Engineers

3. Inadequate fuel pressure (natural gas)

In many areas of the country, the natural gas utility service is much more reliable than electrical utility service. As such, natural gas is often used as fuel for the emergency power supply where a reliable diesel fuel supply cannot be ensured for the duration of an outage.

However, there are some important considerations when selecting natural gas as a fuel source. Historically, buildings were designed around low-pressure gas distribution operating at 6 to 8 inches w.c. This pressure typically cannot accommodate anything other than the smallest generators.

With larger generator capacities, the pressure requirements increase as well. For example, a 1,000 ekW generator — the actual generator output after efficiency losses — may require a minimum of 72 inches w.c. Fortunately, medium pressure gas utility services operating at 2 to 5 pounds per square inch are becoming more common. But even with these higher pressures, sufficient headroom must be provided to account for fluctuations in pressure.

Operation of other gas-fired equipment sharing the same gas distribution or even the demands associated with generator starting can cause unacceptable pressure droop. Natural gas generators are unusually sensitive to fuel pressure changes — for smaller generators, as little as 2 inches w.c. difference between no-load and full-load running conditions can impact generator performance. Inadequate pressure could result in unstable engine speed, sluggishness when responding to large step loads, inability to start and accept load within 10 seconds or general derating of generator capacity.

It should be noted that the generator system typically isn’t the only appliance using natural gas within a building. Over the course of time, it is expected that the other gas appliances (boilers, water heaters, air handlers with gas heat, etc.) will either be replaced or added to a building. When that happen, their potential impact on the generator is often ignored or forgotten about. Unfortunately, because of the intermittent nature of gas appliance usage, gas pressure issues are difficult to identify after the fact. Consequently, any associated changes in a building’s natural gas use caused by the replacement or addition of appliances should be evaluated before installation.

4. EPSS overcurrent protection devices tripped or malfunctioned

Like automatic transfer switches, the overcurrent protection devices within an EPSS often go for long periods of time without proper maintenance. Simple maintenance procedures, such as regularly exercising circuit breakers and switches, are often avoided due to an inability to properly schedule associated outages. It’s not unusual for OCPDs within an EPSS to go for years without being exercised.

Any number of unexpected transient events can cause unexpected tripping of OCPDs within the EPSS. Given the critical nature of the load connected to the generator, a common reaction from the operations and maintenance staff in this situation is to attempt to reclose the affected OCPD and restore power as quickly as possible. That is not the time to find out if the lack of maintenance has caused issues with the proper operation of that OCPD.

Regularly exercising switches and circuit breakers is critical for ensuring that the mechanisms within them can move freely.

NFPA 70B: Recommended Practice for Electrical Equipment Maintenance recommends mechanical testing for molded case circuit breakers at no more than two-year intervals. NETA MTS: Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems, recommends shorter intervals of one year between mechanical testing, which is the more commonly accepted industry practice.

5. Load incompatibility/improper generator sizing

As a building ages, inevitably the various mechanical, electrical and plumbing systems within that building will be replaced as they become obsolete or wear out. However, since they are seldom used, generators have an unusually long service life compared to other equipment. As such, much of the equipment that is supported by the EPSS will be replaced long before the generator is replaced.

While most engineers will use the generator manufacturer’s sizing program when determining a proper selection for a new generator, this design step is often skipped when replacing loads connected to an existing generator. A common misconception is that if the replacement load used the same or fewer kilowatts than the original, then it is a less of a concern because it is a like-for-like replacement. The question is whether it really is a like-for-like replacement?

The most problematic load types for a generator are nonlinear/high harmonic loads. The distorted waveform associated with these types of loads can impact the generator’s voltage regulation and excitation system ability to provide stable output voltage. Unfortunately, most building loads (LED lighting drivers, variable frequency drives, computers, etc.) fall into this nonlinear load category.

To emphasize the issue, it was a once a common design practice to limit uninterruptible power supply loads to no more than 50% of a generator nameplate rating due to the harmonic distortion associated with older UPS 6-pulse silicon controlled rectifier frontends. While insulated gate bipolar transistor-based frontend rectifiers with their dramatically reduced total harmonic distortion levels have largely replaced 6-pulse SCR rectifiers in double conversion UPS equipment, 6-pulse designs are still relatively common in variable frequency drives due to their reduced cost. As such, introduction of large nonlinear loads on an existing generator, such as swapping a VFD for a across-the-line motor starter, has the potential for disaster if not properly evaluated.

Figure 3: A 60-horsepower variable frequency drive is equipped with 5% line reactors for harmonic mitigation. Where nonlinear loads such as VFDs are used, their impact on the generator’s voltage regulation system needs to be considered. Specification of harmonic mitigating equipment may be required. Courtesy: McGuire Engineers

A functional understanding of how a generator works is usefully when illustrating the importance of voltage regulation and excitation systems when supporting nonlinear loads. Generators create output voltage and current by passing a rotating magnetic field (rotor) across a stationary winding (stator). A generator’s voltage regulation and excitation systems are responsible for generating and regulating the direct current that creates the magnetic field within the rotor.

The strength of this magnetic field directly impacts the output voltage for the generator. The automatic voltage regulator senses the generator output voltage and adjusts that rotor magnetic field strength to maintain constant output voltage. If the AVR cannot input sufficient DC excitation current, the generator voltage output will be become unstable. As such, the primary goal of any excitation system is to provide a strong source of power to the AVR so that it can provide sufficient current to maintain the magnetic field under any operating condition.

There are three primary types of excitation systems: self-excited/shunt (SE), auxiliary winding (AUX or AREP) and permanent magnet generator (PMG). SE is the most basic and cheapest type of excitation, but not recommended where nonlinear loads are presents. For SE, the output of the stator provides both power and a sensing source for the AVR. The simplicity of a SE system is also its downfall. If the stator output power is unstable or distorted (such as during a fault condition, motor starting or where high harmonic loads are present) the input power to the AVR also becomes unstable.

Both PMG and AUX don’t use the stator output for the AVR power source. AUX excitation uses a separate set of windings inserted into the main stator windings. While physically distinct from the stator winding, the AUX windings are not magnetically isolated the stator windings. This can impact the stability of voltage delivered to the AVR. PMG uses a discrete permanent magnetic generator that is mechanically coupled directly to the rotor and isolated from an electrical distortion in the stator output. As such, it can provide a strong source of power for the AVR as long as the engine is turning the rotor. Use of PMG is recommended whenever nonlinear loads are expected.

Self-excitation is common in older generators. It typically isn’t feasible to retrofit a PMG excitation system. Where older generators must be used to support new nonlinear loads, the manufacturer should be consulted to determine if use of harmonic mitigating equipment such as line reactors or passive harmonic filters will allow it to support nonlinear loads.


Author Bio: John Yoon, PE, LEED AP ID+C; is lead electrical engineer at McGuire Engineers, Chicago. He is a member of the Consulting-Specifying Engineer editorial advisory board.