Failure and Explosiveness
In general, the useful life of power system components is heavily influenced by the level of care given to them as well as their duty cycles. A circuit breaker, for example, with primarily switching duty can last 40 to 50 years. If no catastrophic events such as lightning strike, the majority of transformers at utilities will last approximately 40 years. Online tap changers in HV transformers, on the other hand, are prone to failure.
Case studies of LV/MV electrical equipment failures and what should have been done (to avoid them)
One of the most significant single causes of failure in MV/LV substations is HV bushings. The failure mechanisms for the surrounding assets tend to develop to a critical level at a midlife point, and such mechanisms generally result in a sudden and catastrophic failure of an explosive nature, significantly shortening the life span of HV substations.
- Failures of CB Bushings in MV Switchgear
If violent bushing failures in MV switchgear occur, they can cause catastrophic damage to the surrounding buildings and plants. A report from the City of Cape Town in South Africa, for example, presents a significant number of such catastrophic failures.
After the manufacturers replaced previously used Bakelite paper bushings with resin-cast bushings, multiple failures began. The substitution was related to the expansion of SF6 and hoover technology, as well as the alleged advantages of resin-cast technology. Resin cast insulators are thought to be more suitable for mass production due to their superior fault toleration, scratch resistance, and mechanical damage resistance.
Some manufacturers would redesign existing breakers to use SF6 and resin-cast technology in order to fit them in the same panel as the older oil breakers. South African utilities used three models of the same manufacturer’s SF6 MV switchgear, which are all interchangeable with previous-generation oil breakers.
However, contrary to popular belief, the City of Cape Town’s experience demonstrated that bakelite paper bushings outperform resin cast bushings by a wide margin.
In 2004, the substation experienced several of the city’s earliest known failures. When staff entered the substation for switching operations, chlorine was strongly moderated. They discovered that the breaker had severe discharge degradation on the bushing insulation and cluster contacts after further inspection. There was also severe corrosion, tracking, and cluster degradation at the substations (Figures 1 and 2).
Figure 1 – Failed breaker with severe discharge degradation on bushing insulation and cluster contacts
Figure 2 – Another case of degradation of CB clusters and bushings
Other defects discovered during the inspection included pores beneath the skin of the bushing resin (manufacturing defects) and misalignment of shutter boxes (signs of poor quality control during manufacturing).
The primary cause of failures was determined to be severe partial discharge activity based on inspection results and root cause investigation. Multiple local regions of electrical stress created within voids, pores, and bubbles in resin mouldings increased the likelihood of partial discharge activity.
However, while most new switchgear panels include heaters, some manufacturers list panel heaters as an option.
A breaker misalignment may play a significant role in increased partial discharge activity. Because the apertures in the shutter box are unevenly spaced, the electrical field around the bushing is inconsistent if the breaker bushings and corresponding orifice bushings are out of alignment. Misaligned shutter boxes could produce the same result.
Breakers that are not correctly aligned risk damaging the orifice (female) bushing and tracking. Operating these breakers could be dangerous.
Figure 3 – Severe corrosion degradation of circuit breaker clusters
Figure 4 – Severe corrosion degradation of circuit breaker and tracking on the bushings
- MV Switchgear Failure Case Studies
The failures of MV switchgear can be attributed to poor design. Inadequate maintenance procedures, on the other hand, that fail to stop and identify mechanical and electrical issues that cause failures, are more frequently to blame. Increased load densities also put a strain on the infrastructure of today’s outdated MV switchgear.
Solutions frequently strive to balance competing demands such as maintaining high availability and reliability while keeping costs low and providing the highest levels of safety.
Errors in design, component defects, and human error, or a combination of these, can all lead to severe MV switchgear failure.
Case #1: Defective Component
The following failure occurred with a feeder breaker that was removed for CM testing. The breaker was racked in the “test” position, and the timing test wires were attached to the breaker’s arms. When the breaker was inserted in the “test” position, it flashed over. The failure of the mechanical interlock was discovered to be the cause of the flashover.
When the test equipment’s metallic clamp was connected to the breaker, it came within arcing distance of the live busbar, resulting in the flashover.
Suggested Reading – Why is remote racking of LV/MV circuit breakers a wise investment but so uncommon?
Case #2: Arcing and Breaker Design Mistakes
The medium voltage breaker failed during fault clearance, severely damaging the switchgear room’s doors and windows. Following a root cause analysis, it was determined that the arc created a pressure wave that was unable to escape, causing damage to the door and windows.
This damage could have been avoided if the pressure wave outlets had been installed as hinged louvres at various points throughout the switchgear room. During normal operation, these louvres remain closed, preventing outside dust from entering the room.
When an electrical arc generates a pressure wave, the pressure is released through these louvres, preventing harm to the switchgear room and the operating personnel present.
Figure 5 – Medium voltage circuit breaker arcing damage (photo credit: Farrukh Habib via Reddit)
2.3 Case #3: Water Condensation and Flashover
A flashover occurred in the breaker compartment due to a charged feeder carrying no current. The space heater in the breaker compartment was discovered to be defective (manufacturing defect).
As a result, condensation in the breaker compartment would be reduced. Flashover occurred because there was water condensation in the compartment as a result of the heater being turned off and the load current being zero.
Suggested Reading – When racking in and racking out circuit breakers, use extreme caution.
2.4 Case #4: Outdated Operational Instructions
A serious arc flash incident causes equipment damage.
A worker was performing process (not electrical) isolation as part of routine pump maintenance. When the medium voltage (MV) 3.3 kV isolator was switched, a significant arc flash and blast occurred, partially opening the switchgear control cabinet door. There was a risk of serious injury to the worker, as well as damage to the switchgear equipment.
The worker was fortunate to be wearing Category 4 arc blast-rated personnel protective equipment, including hearing protection, and to be physically unharmed.
Despite the fact that the active front end had recently been added to the installation, the operational instructions had not yet been updated to reflect this change.
Figure 6 – Switchgear panel with front and rear panels removed and damage from the arc blast. See the condition of the busbars that are broken
Possible causes include:
Direct:
Although the main isolating switch was supposed to be activated once the variable speed drive (VSD) contactor opened, the isolation was performed while the contactor was still closed and reactive current was flowing.
Because the main isolating switch was not designed to interrupt the highly reactive current flow, it was unable to do so.
Indirect:
Because a mechanical interlock between the two devices failed, it was possible to operate the isolator while the contactor was still engaged.
The arc blast protection was missing from the switchgear cabinet.
During the switching process, the design and operation requirements for this type of drive were not taken into account.
2.5 Case #5: Overheating Breaker
During service, an MV hoover circuit breaker (22 kV, 2500 A) failed. Following a failure analysis, it was determined that the current-carrying component of the breaker had overheated while supplying the nominal load current. The overheating was demonstrated by performing a Heat Run test, which revealed that the TR was exceeding allowable limits.
To prevent overheating with the breaker inside the cubicle, a 20% derating factor was required, particularly for feeders carrying more than 70%-75% of the breaker/switchgear-rated current.
Reading Suggestion – How to Design a Fault-Tolerant and Reliable Facility Distribution System
Failures of Metal-Clad Switchgear
Let’s look at two failures of metal-clad switchgear, one at a US nuclear power plant and the other at a foreign nuclear power plant (NPS). The most fascinating aspect of both incidents was how an electrical fault in one breaker cubicle caused damage to other breakers and buswork in the same enclosure.
These electrical occurrences help us understand the potential collateral damage, cascading failures, and plant operation challenges that a single electrical failure could cause.
3.1 Case #1: 25-Year-Old CB Failure and Lack of Maintenance
While shifting loads to the unit auxiliary transformers, a fault on a 4.16 kV supply CB from the unit auxiliary transformer caused a fire and the loss of offsite power. The C phase main contacts on the 4.16 kV breaker did not completely close, which was the source of the problem. This caused arcing and the emission of a thick, dark ionised smoke. The breaker was a three-pole, MV AC power CB with continuous ratings of 3000 A and 350 MVA (interrupting).
The breaker’s last preventive maintenance was four years ago.
Figure 7 – AC Power Distribution System with Y Connection to Safety Buses
The conductive ionised smoke diffused through conduits and holes between adjacent cubicles, cutting off off-site power. As a result, the energised incoming terminals of the backup auxiliary transformer’s offsite power supply were shorted. The fault blew off the insulating boot that covered the A phase busbar and the offsite supply CB’s cubicle door.
To clear the fault, the HV supply breakers upstream of the reserve auxiliary transformer were opened. This cut off the unit’s non-essential offsite power. Due to the loss of off-site power, the turbine lube oil pump was forced to run without regard for safety.
The failure of the DC supply breaker for the lube oil pump caused significant damage to the main turbine.
Case No. 2: Insulator Failure
A fault in a 4.16 kV load centre at a foreign nuclear power station caused a fire and the loss of offsite power, while the reactor was shut down but with significant decay heat.
This resulted in a station blackout, which was caused by an independent failure in the onsite standby power supply (i.e., a loss of AC power to both redundant safety systems).
Smoke and the reliance on AC-powered emergency lighting and ventilation complicated the recovery process even more.
The insulators on the 345 kV transmission system had salt deposited on them from days of foggy, misty weather, causing power fluctuations and outages. The 345 kV transmission system had been disrupted the day before the failure, resulting in an automatic reactor shutdown and transfer to an offsite source of 161 kV.
The 345 kV source was recovered on the day of the failure, and the circuit into the plant was reenergized, with the reactor shut down and the unit receiving offsite power from the 161 kV backup source.
A fault occurred in the A train 4.16 kV load centre after the switchyard 345 kV CB was closed (energising the 345/4.16 kV transformer and the 4.16 kV circuits into the vital load centres while the 4.16 kV supply breakers remained open). The fault was caused by an insulator failure on one phase of the A train 4.16 kV safety-related switchgear on the supply side of the 345/4.16 kV transformer’s supply breaker.
Due to an unrelated failure of the other onsite power source, both trains lost all power. In addition, due to the loss of off-site power, the backup station’s blackout power supply was disabled.
Technical specifications for the construction of 33/11 kV 231.5 MVA substations are recommended for study.
- MV Power Cable Failure
Several factors contribute to the failure of medium voltage (MV) power cables. The most commonly used cable insulation materials are PE (XLPE, tree-retardant cross-linked polyethylene [TR-XLPE], and high molecular weight polyethylene [HMWPE]) and ethylene propylene rubber (EPR). Excessive pulling tension, water treeing, and corrosion have all been identified as causes of underground power cable failures.
HV surges may blow holes in the jacket and damage the shield, and water may enter through the holes and cause corrosion.
MV power cables are often located in inaccessible locations such as conduits, cable trenches and troughs, duct banks, underground vaults, or in other directly buried installations; under such conditions, they can fail due to insulation degradation.
Very often, partial discharge activity in power cables causes the failures. partial discharge is accelerated by various defects, such as voids, shield protrusions, contaminants, advanced stage of water trees, and so on. Partial discharges will gradually degrade and erode the dielectric materials, eventually leading to the final breakdown.
Medium Voltage Cable Failures: Root Causes and Online Detection
- Ageing,
- Corrosion of sheath,
- Electrical puncture,
- Moisture in the insulation,
- Heating of cable,
- Fire and lightning surges,
- Damage while in use due to excavation works, or
- Damage during laying.
4.1 Failed Cable Example #1
The first case studied was an 11 KV PICAS to XLPE Branch adapter that failed one hour after installation. Following an investigation, the proximate cause was determined to be incorrect adapter tube positioning. Workmanship errors, on the other hand, were determined to be the ultimate cause of failure.
Many quality issues were discovered during the investigation. There was no putty in the shear bolts, the tubing was poorly cut, and there were gaps in the insulation throughout the sample. Common recommendations for these conclusions include retraining the jointers and evaluating the components completed as part of this project.
This example demonstrates that identifying and correcting the single proximate cause of the failure is insufficient. There were several errors that would have all resulted in failure if the first cause had not been present. All workmanship issues and potential failure points would be addressed by addressing the root cause of jointer training.
Figure 8 – XLPE/PICAS joint failed
4.2 Failed Cable #2 Exemplification
The following case study looked at a 33KV XLPE joint that failed after 18 months of service. Figure 9 shows the fault hole visible through the insulation. The failure occurred because the jointer did not properly deburr a connector. The sharp edge caused mechanical damage as well as an electric field concentration in the damaged insulation.
The takeaway from this failure was that poor comprehension of instructions, a lack of attention to detail, and a lack of training all contributed to the joint’s failure.
Figure 9 – Failure location on 33KV XLPE joint
4.3 Failed Cable #3 Exemplification
The final case studied is a Paper Insulated Lead Covered (PILC) cable that failed after 47 years of service (nice age, by the way!). Figure 10 depicts a mid-cable failure of an 11KV cable. This failure was caused by age-related partial discharge. Despite the fact that this cable had an adequate life span, this is an example of how partial discharge mapping could have prevented an unplanned failure.
If the partial discharge had been detected earlier, the client could have planned an outage to address the issues.
Figure 10 – Failed Paper Insulated Lead Covered (PILC) cable
With cable failures costing clients millions of dollars each year, identifying trends in occurrences can help reduce future failure costs. Forensic analysis enables the community to learn from previous failures in order to promote a more dependable and robust system.
The following conclusions were reached after reviewing 73 forensic analysis reports:
Conclusion #1 – Cable faults have a predictable reliability curve and should fail within the first 10 years or after 40 years of service. With approximately 35% of failures occurring in the first ten years, it is critical that they are carefully installed to prevent the majority of infant mortality-related faults.
Conclusion #2 – By ensuring that installations are carried out in accordance with clear and accurate manufacturer’s instructions, two-thirds of faults could be avoided.
Conclusion #3 – Because human error is unavoidable in all fields, a proper asset management programme based on partial discharge testing can assist in identifying and prioritising issues as they arise.
Although these reports have revealed universal trends, they do not necessarily imply that every company should prioritise the recommendation in the same way.
Handbook on EHV overhead lines and underground cables is a recommended resource.
Failure of a Low-Voltage Switchboard
Consider the failure of a switchboard in a community infrastructure-related facility. The damaged switchboard had a supply bus rating of 1250 A, a section bus rating of 1250 A, and a neutral bus rating of 630 A (see Figure 11). The short circuit rating of the switchboard was 25,000 A. The system was 480/277 V, three-phase, four-wire.
The switchboard, the main breaker, the bus, the metering compartment, and another bus nearby were all physically inspected. The majority of the arcing damage was discovered in the main breaker cubicle, vertical bus, and metering compartment above the breaker.
Corrosion was discovered within the failed breakers and their connections, as well as on nearby breakers, during the inspection. Hydrogen sulphide was discovered in the air of the breaker’s electrical room. The hydrogen sulphide caused corrosion and flaking of the finger cluster surfaces over time. This gas also attacked the mating surfaces of the breaker cubicle bus connections (stabs), so they too corroded and flaked.
Figure 11 – Destroyed low voltage switchboard due to the arc flash
The following sequence of events was proposed as the cause of the failure:
Electricians tripped the main breaker about 20 days before the failure. The electrical connection had higher than normal electrical resistance because the contact surfaces of its finger clusters and stabs were irregular and corroded. The extra heat produced by the load current passing through these connections accelerated further oxidation and deterioration of the connection surfaces.
This, in turn, exacerbated the heating issue. The heating was intense enough to melt the B phase connection surfaces on the centre (B) phase. The normal load current generated an arc that bridged the small gap formed by the melted copper surfaces.
Separate phases may have made contact due to melted wiring insulation, or the melted fuse block may have done the same. Because the short circuit in the control wiring was on the line side of the breaker and the line side of the control wiring fuses, it did not cause the main breaker to open or the fuses to blow.
Learn to Read and Analyze CB Schematics and Control Wiring Diagrams is a recommended course.