TM ELECTRONICALLY REPRINTED FROM FEBRUARY 2016 EquipmentProtection Is Your Transformer OK? Enhanced safety is the reason PG&E has internal fault detection on all new overhead transformers. By Roozbeh Movafagh, Pacific Gas and Electric Co., and Dan Mulkey , Mulkey Engineering C atastrophic failure of an overhead transformer is a rare occurrence, but it does happen. Electrical sys- tems are designed so protective devices, like fuses, operate first and protect more important devices, like transformers. A blown fuse is not uncommon and can be caused by several fault conditions: wildlife getting between en- ergized conductors, cars hitting utility poles, lightning strikes and overloaded circuits. Blown fuses are simply replaced and reclosed, re-energiz- ing the line section or the transformer the blown fuse de-ener- gized. Sometimes the fault that blew the fuse also damages the transformer. This is often apparent if there is damage to the transformer tank or the pressure relief device has blown out. But in very rare cases, the transformer fails with no outward sign. This can be a dangerous situation. So as part of Pacific Gas and Electric Co.’s (PG&E’s) continuous effort to improve safety, the utility has embraced the use of internal fault detec- tors on all new overhead transformers. The Beginning In 2000, a PG&E lineman escaped serious injury when an overhead transformer he was working on exploded. To sup- ply energy, PG&E put up a conventional single-phase over- head transformer, which became overloaded; within a few weeks, both of its fuses blew. (For the most part, PG&E is a phase-to-phase connected system, so most transformer instal- lations have two or three fuses.) There was no outward sign the transformer had failed, but it had. The lineman replaced both fuses, closed them into a dead short and the transformer exploded. The force of the explosion inverted the lid and then sent it flying. Fortunately, the lineman was wearing the appro- priate personal protective equipment and was not hurt. After this incident, PG&E revised its operating proce- dure by restricting re-energization attempts when the cause of a transformer outage cannot be determined. If there are no signs of damage to the transformer and if only one fuse is blown, then and only then do PG&E linemen replace the fuse and try to re-energize the transformer. If two or three fuses are blown, PG&E linemen assume the associated transformer has failed and replace it, regardless of its appearance. These changes in operating procedure were a good first step, but PG&E wanted to take it further. Since the utility has more than 1 million distribution trans- formers, with the majority of the units being overhead units, outages happen every day. Many times the failure is ob- vious, corrections are easily made, and the transformer is re-fused and service restored. Sometimes it takes more inves- tigation to uncover the cause and some- times no cause is found, the transformer is re-fused and power is restored without incident. Then there are those rare cases where the transformer looks fine, is re- fused and fails catastrophically when re-energized. Even though such cata- strophic failures are atypical, PG&E looked for a way to prevent them. Then in 2001, some of PG&E’s electrical engi- neers went to the IEEE T&D Exposition in Atlanta, Georgia, U.S., and attended a presentation by Paul Chisholm, presi- dent and CEO of IFD Corp., about An internal fault can be violent enough to blow the lid off a transformer.
Transcript
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ELECTRONICALLY REPRINTED FROM FEBRUARY 2016
EquipmentProtection
Is Your Transformer OK?Enhanced safety is the reason PG&E has internal fault detection on all new overhead transformers.By Roozbeh Movafagh, Pacific Gas and Electric Co., and Dan Mulkey, Mulkey Engineering
Catastrophic failure of an overhead transformer is a rare occurrence, but it does happen. Electrical sys-tems are designed so protective devices, like fuses, operate first and protect more important devices,
like transformers. A blown fuse is not uncommon and can be caused by several fault conditions: wildlife getting between en-ergized conductors, cars hitting utility poles, lightning strikes and overloaded circuits.
Blown fuses are simply replaced and reclosed, re-energiz-ing the line section or the transformer the blown fuse de-ener-gized. Sometimes the fault that blew the fuse also damages the transformer. This is often apparent if there is damage to the transformer tank or the pressure relief device has blown out. But in very rare cases, the transformer fails with no outward sign. This can be a dangerous situation. So as part of Pacific Gas and Electric Co.’s (PG&E’s) continuous effort to improve safety, the utility has embraced the use of internal fault detec-tors on all new overhead transformers.
The BeginningIn 2000, a PG&E lineman escaped serious injury when an
overhead transformer he was working on exploded. To sup-ply energy, PG&E put up a conventional single-phase over-head transformer, which became overloaded; within a few weeks, both of its fuses blew. (For the most part, PG&E is a phase-to-phase connected system, so most transformer instal-lations have two or three fuses.) There was no outward sign the transformer had failed, but it had. The lineman replaced both fuses, closed them into a dead short and the transformer exploded. The force of the explosion inverted the lid and then sent it flying. Fortunately, the lineman was wearing the appro-priate personal protective equipment and was not hurt.
After this incident, PG&E revised its operating proce-dure by restricting re-energization attempts when the cause of a transformer outage cannot be determined. If there are no signs of damage to the transformer and if only one fuse is blown, then and only then do PG&E linemen replace the fuse and try to re-energize the transformer. If two or three fuses are blown, PG&E linemen assume the associated transformer has failed and replace it, regardless of its appearance.
These changes in operating procedure were a good first step, but PG&E wanted to take it further. Since the utility has
more than 1 million distribution trans-formers, with the majority of the units being overhead units, outages happen every day. Many times the failure is ob-vious, corrections are easily made, and the transformer is re-fused and service restored. Sometimes it takes more inves-tigation to uncover the cause and some-times no cause is found, the transformer is re-fused and power is restored without incident.
Then there are those rare cases where the transformer looks fine, is re-fused and fails catastrophically when re-energized. Even though such cata-strophic failures are atypical, PG&E looked for a way to prevent them. Then in 2001, some of PG&E’s electrical engi-neers went to the IEEE T&D Exposition in Atlanta, Georgia, U.S., and attended a presentation by Paul Chisholm, presi-dent and CEO of IFD Corp., about An internal fault can be violent enough to blow the lid off a transformer.
See the signal,replace the transformer.
www.ifdcorporation.com
Faster troubleshooting...much faster.By design...Safer restoration.Operations that are simply...Better.
FAULT
replace the transformer.
EquipmentProtection
the company’s internal fault detection (IFD) device. The small device mounts through the wall of the trans-
former case and detects any sudden rise in pressure. If that occurs, a highly visible button pops out, warning line workers the transformer has experienced an internal fault. The IFD does not activate if the internal pressure rises slowly, only if the pressure increase is rapid, and is not the same as a pressure relief valve (PRV).
IFD vs. PRVA major disconnect exists between people’s perception of
what a PRV does and what it actually does. Many people, even those in the industry, think the PRV prevents the transformer tank from rupturing during a fault or keeps the transformer lid from flying off, but it does not; the vent opening is just too small for high energy faults. This misunderstanding likely came about because the design of the tank and cover system was strengthened to improve its fault performance about the same time PRVs came into wide use. But even the tank design where the cover itself operates as a PRV and provides a much larger vent opening is not big enough to retain the lid under all fault conditions.
The main purpose of the PRV is to equalize the internal pressure with the external pressure. This keeps transformer covers from flying up into the face of the lineman who is try-ing to unhook the cover to change the secondary leads, or into
A typical overhead transformer installation with fused cutouts before the adoption of the use of internal fault detection.
EquipmentProtection
The force of an internal fault inverted the lid, which is still attached to the center post, causing a catastrophic failure.
the face of a worker in the repair shop who is trying to repair the transformer. For a low- to mid-level energy internal fault, the PRV may operate to relieve the internal pressure. However, PRV operation does not reliably indicate the transformer has failed. PRVs can operate and indicate, even ejecting some in-sulating fluid, just from load and temperature changes.
The IFD includes a PRV, so the pressure can be reduced when it is necessary to open up the transformer. But it also indicates when there has been a sudden rise in pressure, and that is the key. During a low-impedance internal transformer fault, there is not a gradual buildup of pressure like when a transformer heats up as a result of high loads or rising ambient temperatures. The low-impedance fault generates an almost instantaneous pressure spike. This triggers the IFD, popping out the red flag and warning the lineman. Such a low-imped-ance fault is the most dangerous kind of fault, as re-energizing the unit can result in the transformer cover flying off.
Field ExperienceWhile the IFD was new to PG&E, the utility’s engineers
learned at the IEEE T&D Expo in Atlanta that IFD Corp. had been working with Hydro-Québec for some time and had ex-tensive utility experience. PG&E’s engineers talked to IFD’s Chisholm as soon as he finished his presentation. Together, they walked out onto the show floor and tracked down the overhead transformer vendors PG&E had been buying from at that time and talked to them about the possibility of getting
the IFD device installed in PG&E’s new overhead units. It was that fast.
In 2002, IFD Corp. came to San Francisco, California, U.S., and made a presentation to PG&E engineering, operations and quality managers. During the meeting, one of the opera-tions staff commented that re-energizing faulted units was more common than people realized. It was also pointed out that it is often difficult to tell if a transformer has failed by sim-ple observation or even using some field testing procedures.
IFD ImplementationPG&E buys several thousand new transformers per year
and the majority of them are overhead transformers. There-fore, getting IFDs in each one was going to take some work. In 2004, PG&E instituted a pilot project involving a couple hundred transformers with IFDs. PG&E worked closely with its suppliers to change their procedures and install a new de-vice into their units. IFD Corp. sent its engineers down to work with the suppliers’ engineers and plant personnel to ensure the installation of the IFD was optimized for their manufac-turing processes. The units were put into the regular stock at PG&E and went out to the field wherever they were needed.
PG&E experienced one small problem during the pilot that IFD Corp. corrected. The pilot project was an overall success. For purchases beginning in 2009, PG&E revised its engineer-ing material specification 82 for single-phase and three-phase overhead distribution transformers to require the inclusion of the IFD.
No RetrofitsWhen PG&E first ramped up to full-scale implementation
of the IFDs, the utility considered adding IFDs to the trans-formers when they were refurbished. However, there were numerous practical reasons not to do so.
This transformer was returned to the shop after failing in the field. The IFD has popped and the exposed red is easily visible, even from the ground.
First, just 2% to 5% of distribution transformers that come through PG&E’s transformer shop are considered worth re-furbishing. Most are sent for scrap because of damage or age. Because the transformer itself is a minor part of the total cost of a transformer replacement job, there is no real advantage to returning a 10-year-old unit to service.
Second, the IFD has to be installed on a flat surface and overhead transformer cases are curved. While such geometry issues may not be significant at the manufacturing plant, they do create difficulties for a retrofit. Similarly, while the hole punched into the case for the IFD is round, it also has a small notch. Making that notch would require tooling the PG&E’s transformer shop does not have.
Response and CostWhile there was some initial resistance to the IFDs, PG&E’s
linemen are happy with the change overall. Having an IFD on the transformer makes one aspect of line work a little easier and safer. That is a good thing, as there is nothing more im-portant than public and employee safety to PG&E.
For transformers without an IFD, PG&E continues follow-ing its revised procedures, namely, to err on the side of safety by removing (rather than re-fusing) transformers based on the number of fuses that operated.
For transformers with an IFD, PG&E has modified its procedure so, if the IFD indicates a fault, the lineman always changes out the transformer regardless of the number of fuse operations. If the IFD does not indicate a failure, then even if two or three fuses have blown, it is fine to install new fuses and try the transformer.
The IFD does add to the cost of transformers — about 10% more to the smallest units — but PG&E thinks it is worth it in the long run. IFDs make troubleshooting easier and en-hance safety. If the IFD has indicated, the transformer has failed.
Rudy Movafagh ([email protected]) joined Pacific Gas and Elec-tric in 2008 and was appointed to lead the Electric Distribution Standards Group in 2009, of which he is now senior manager. He started at Boston Edison in 1983 as distribution engineer with emphasis on underground secondary network system. He worked in various capacities and was promoted to lead the distribution engineering for NSTAR in 1997. In 2003, Movafagh was hired by Danvers Electric to manage distribution substation and automation activities. He currently serves as an advisor and board member representing PG&E in National Electric Energy Testing Research and Applications Center.
Dan Mulkey ([email protected]) is a professional engineer, chair of the underground transformers and network protectors subcommittee, and chair of the enclosure integrity working group of the IEEE transformers committee. Mulkey started work at Pacific Gas & Electric in 1973 as an engineer trainee. He rose through the ranks to senior consulting electrical engineer, at which he retired in January 2015. He then founded Mulkey Engineering, in Petaluma, California, and now works for PG&E as a consultant.
As shown from the inside, the IFD is installed through a hole in a flat area of the transformer case.
For more information:Hydro-Québec | www.hydroquebec.com
are saying!“Finally, a safety product that makes us money.”Vice President Distribution, IOU
“Great product, and it’s an easy business case - the IFD is a capital expenditure vs. an O&M expense.”Vice President, IOU
“Many of our transformers are located across far distances. This will help us to avoid wasting time going back and forth.”Lineman, Co-op
Failed?
IT’S ALL ABOUT POLE-MOUNTED DISTRIBUTION TRANSFORMERS. Like every other utility, line crews at Hydro-Québec (Montreal, Canada) find reclosing on distri-bution transformers both potentially dangerous and time consuming. With fuses blown and reclosers open, deciding when to re-fuse a transformer and put it back in service can be difficult. Is it just the fuse, or has the transformer faulted?
The Internal Fault Detector (IFD) from IFD Corp. (Van-couver, Canada) was in development for more than a decade, and represents the result of a collaborative research and de-velopment effort involving financial and technical support by the National Research Council, a group of utilities and CEA Technologies Inc. (Montreal). The objectives for the IFD were to improve worker productivity, enhance customer service and increase overall safety associated with transformer failures. More than 45% of all new pole-mounted transformers in Canada are now shipped with an IFD.
Until recently, there had not been a sound, reliable test—with-out disconnecting the transform-er and applying voltage—to detect faulted pole-mounted transform-ers. Hydro-Québec now uses IFDs that physically flag faulted pole-mounted transformers.
The IFD has two functions. It incorporates the pressure-relief device (PRD) and provides a visu-
al indication on whether the transformer has faulted inter-nally. The PRD conforms to ANSI’s PRD standard, and the sensor inside the IFD detects pressure changes in the airspace above the oil that are caused by internal faults.
The IFD sensor is calibrated to respond only to pressure changes due to faults, not to normal pressure changes due to increased load or rising ambient temperatures. When a fault is detected, an orange indicator, which can be seen from the ground, pops out. The line crew knows immediately that the transformer needs to be replaced. No time is wasted even considering the bad decision to reclose on the transformer. No one is placed in danger, and the utility saves time and money.
DISTRIBUTIONEquipment
Has the Tranformer Hydro-Québec goes proactive to ensure line worker safety, improve customer satisfaction and increase operational efficiency.by Daniel Desrosiers, Hydro-Québec
Prior to operation, the pressure-detecting mem-brane and its trigger shaft (red and blue vertical rod) are in the lowered position, locking the in-dicator (yellow) in place. The large spring on the right side stores the energy to push the indicator out; the small coaxial assembly on the left is the pressure relief device (PRD).
When the membrane reacts to the pressure pulse caused by an internal fault, it moves up, carrying the trigger shaft with it (red and green). This releases the indicator, which is pushed out by the spring. Once this happens, pressure is re-lieved through the IFD. The blue arrows indicate the flow of gas through the indicator assembly.
ELECTRONICALLY REPRINTED FROM OCTOBER 2006
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EFFICIENCY
Like all utilities, Hydro-Québec continuously looks for ways to increase efficiency. So, if you consider the time it takes to properly reclose on a potentially dangerous transformer, there is a real operational advantage to using IFDs because they remove the time-consuming decision-making process (return to service or replace) to determine if the transformer is faulted. Our experience has been that only one out of four transformers is usually faulty.
When an IFD has activated, a line worker or scout can call the dispatcher and report that the transformer has faulted, the size of the transformer and the location. Hydro-Québec then sends a replacement team. When the line worker determines the transformer has not faulted, the worker can look to differ-ent causes for the fuse operating before starting the process of safely re-energizing, which leads to a faster, safer resolution of the problem. So, in all circumstances where the fuse has oper-ated and an IFD is installed, the line worker saves time.
SAFETYHydro-Québec has an objective of zero acci-
dents. The utility also has some of the strongest safety-oriented policies
in the utility industry. The de-cision to use the IFD is one of
the many policies that address this objective. When you try to increase the efficiency of your process, you have to maintain, if not increase, the safety level.
Before including the IFD in its transformer specification,
Hydro-Québec toured the manu-facturing facility. IFDs are manufac-
tured with stringent quality control, and each IFD is tested in the lab before being shipped. Therefore, it is high-ly unlikely an IFD device would give a false negative. Even so, mechanical failures are possible. To be on the safe side, IFD Corp. recommends that transformers where the IFD has not operated be reclosed following each utility’s standard safety procedures.
CUSTOMER SATISFACTIONCustomer service is important to Hydro-Québec. By making
diagnoses faster and improving the efficiency of trouble crews, utilities can reduce the system average interruption duration index. Restoration is quicker because time is not spent restor-ing what is faulty. All the information is rapidly being sent to the dispatcher, who then decides how many transformers to send and how many work crews to assign.
Hydro-Québec is considering launching a public-awareness campaign to let customers know about IFDs. The company would ask the public to check for an IFD on their transform-ers and, if they do see the orange indicator of an IFD, to let Hydro-Québec know so it can make a no-light call. It would be easier for Hydro-Québec to know which kind of crew it has
to send on the trouble call, which means faster resto-ration and increased custom-er satisfaction.
WEATHER IMPACTLike every other utility,
Hydro-Québec finds dealing with outages, especially ma-jor storm outages, challeng-ing—particularly if there have been many lightning strikes. In a severe lightning storm, literally thousands of fuses can operate in a limited geographic area in a period of only a few hours. This puts
Shows a typical distribution pole top with a blown fuse cut-out to the transformer. This transformer is equipped with an IFD that is indicating with the orange flag that the transformer has an internal fault and should be removed from service.
DISTRIBUTIONEquipment
TRANSFORMER FAILURE DATA CEA Technologies Inc. analyzed how pole-mounted transformer tanks actually
fail in service. Their report documents that of a population of more than 400,000 units, there were approximately 20,000 (5% of population) fuse operations per year. In these fuse operations, a total of 4000 units (1% of total population) failed per year. About one in 270 of the failed unit operations was explosive in nature. Or, there are about 15 explosive failed unit reclose operations annually. The population was in eastern Canada and the researchers expect that in areas with greater lightning activity, the percentage of failed units would be greater.
There are more than 50 million distribution transformers in service in North America. And, applying the CEA Technologies Inc. findings about failure incidence to this larger population, one would expect between 1100 and 1800 explosive transformer reclosings annually without IFD applications or if no checks or precautions were taken.
tremendous pressure on the linemen who are working to re-store power. As transformers fail in these areas, they are be-ing replaced by units with IFDs. So, units with IFDs are finding their way into the areas they are most needed. Annually, Hy-dro-Québec replaces 3000 faulty transformers, which has been the average over the last 10 years.
HARD NUMBERSHydro-Québec has more than 3.3 million customers and
about 550,000 pole-mounted transformers. Each year, the utility installs between 10,000 and 12,000 new units—all of which have IFDs installed by the transformer manufacturer.
Hydro-Québec’s line workers would like a higher penetra-tion rate, but this is not possible yet. The most efficient method for getting IFDs onto a system is through the installation of new transformers (either through new construction or the re-placement of existing units). It is possible to retrofit a unit with an IFD, but the costs associated with removing the transformer from the pole to do so are currently too high to make it cost effective. On the other hand, the cost to have an IFD installed
in a transformer already in the shop is rel-atively low.
Since Hydro-Québec has been specify-ing IFDs in all new pole-mounted trans-formers for three years, total penetration is about 12%. Nevertheless, even with this fractional penetration, the company is seeing results.
THE RIGHT DECISIONAfter using the IFD for three years,
Hydro-Québec wanted to assess the finan-cial impact of introducing the IFD on pole-mounted transformers. To do this evaluation, Hydro-Québec first looked into events influenced by the presence of IFDs in transformers.
Experts were consulted to establish the impact of having, or not having, IFDs in transformers. These experts used reliabil-ity data, frequency and duration of events to build the business model for a single
year of purchase of transformers equipped with IFDs. Finally, they built cash-flow models based on the impact of their data analysis.
The data showed that, typically, replacing a transformer requires:
l Four hours for a two-linemen team if they can use their equipment, such as a boom truck
l Six hours for a five-linemen team if the transformer is sit-uated in a back-lot location.
In the case where there is no evident cause for the fuse operation, testing or inspection is required before re-energiz-ing the transformer. These experts estimated that 70% of the time having an IFD-equipped transformer, diagnostic, testing and inspection prior to closing the fuse, can be reduced by 30 minutes to 1 hour.
When calculating the net present value of having certain transformer populations equipped with IFDs, the following hypotheses were used:
l Additional cost of the IFD: US$40l Transformer life expectancy: 30 years
A typical shot of a line worker reclosing a re-fused cut-out. Without an IFD there is no way to know the consequences of this action.
This is the possible result of reclosing on a transformer with an internal fault. This photo was staged at a utility test lab with a mannequin, not a line worker, and the reclose onto the line voltage was done remotely.
DISTRIBUTIONEquipment
l Transformer’s fuses operation rate: 3.8% (spread evenly over the life of the transformer)
l Annual purchase: 10,000 transformersl Hourly linemen team rate: $232
DISTRIBUTIONEquipment
l No dollar value for incident/accident reductionl No dollar value for positive reliability impact (downtime
reduction).The resulting business case showed that on a 30-year
planning horizon, the net present value for an additional dollar spent toward IFD installation in pole-mounted distribution transformers is es-timated at $1.55. Additionally, in the long term, Hydro-Québec expects the IFD to provide better diagnostic information that should prevent non-required replacements of transformers (300 units per year estimated).
Furthermore, no dollar value was attributed to downtime reduction for customers and lower risks for linemen since these issues are strategic in nature.
From this data, the conclusion is that includ-ing IFDs in transformers is not only a good risk-re-duction practice, but also produces an excellent return on the initial investment. More strategical-ly, the IFD represents another small step on the journey to a distribution system where, more and more, information is used to improve customer service and the effective utilization and safety of valuable resources.
Daniel Desrosiers is manager of Research & Development and Special Projects at Hydro-Québec Distribution, and business risks coordinator for the Distribution Network business unit. He has more than 25 years experience in planning, engineering and operation of both transmission and distribution systems in Canada. Desrosiers is also acting as a designated expert on the IEC international standard committee related to network design, chairman of the Canadian National Committee, and he contributes actively to CEA technical committees. Desrosiers is a registered professional engineer.
