Transformers are the heart of an

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1 98 Technical Article Reliability of Electrical Systems: From Testing to Monitoring Specific data from a fault gas monitor study will be presented, as well as a test case that focuses on the relationship between risk and reliability. In the past, chemical, mechanical and electrical testing were relied on to determine the detectability of failure. With the great increase in the use of on-line fault gas monitors, determining more timely potential faults means potential failures can be anticipated, thereby reducing the high consequential costs of those failures. Author Alan M. Ross SD Myers, Tallmadge, Ohio, USA alan.ross@sdmyers.com Transformers are the heart of an electrical system, so any discussion of reliability must start with the transformer. While reliability standards have been developed for most production equipment, one significant area that lacks clear reliability standards is the transformer. Certainly the Institute of Electrical and Electronics Engineers (IEEE), the International Council on Large Electric Systems (CIGRE), the International Electrotechnical Commission (IEC) and ASTM International have developed very robust standards within their areas of expertise. Transformer reliability, however, has not been an area on which most industrial facilities or companies focus. Why? It is highly likely that the risks associated with potential failures have been overlooked. Unfortunately, those risks are now threatening the productive capacity of plants and facilities to avoid unplanned outages. This paper will review a model of what a transformer reliability program should look like and present a case study within the steel industry on the implementation of an electrical system reliability program. Discussion Risk and Reliability The formula below illustrates the Risk/Reliability equation: Risk of Failure = Probability Consequence Detectability While the probability of transformer failures has been very low for decades, it has been increasing. However, it is the dramatic increase in the consequences resulting from an unplanned failure that is alarming, especially when that failure is catastrophic. So while the probability is merely edging up, the consequences from failures are increasingly spiking. The response from many professionals is that they have begun to replace aging units with newer units that they believe will eliminate this probability of failure. Unfortunately that is not the case. Newer transformers are at a significant degree of risk based on several factors. For decades the bathtub curve has been relied on, which projects higher failures at start-up for one year and then a leveling-out of risk. A recent presentation by Omicron has moved that initial risk to three years from one year. So, replacing old units does not necessarily eliminate the probability of failure. Why? In the past, elaborate slide rules were used when designing or engineering equipment. Today, computer modeling allows transformers to be built to exacting and precise standards. In short, transformers are not overbuilt anymore. More entrants into the transformer original equipment manufacturer (OEM) market also means greater price competition, which has led to greater cost controls. Probability of Failure Transformers suffer from a malady that seems to mirror a growing issue in society: they are aging. Failures have skyrocketed over the past decade from less than 2% to less than 3% per insurance industry feedback. This is not much of an increase. One transformer insurance carrier has shared that their experience is less than 7%, which actually might be considered skyrocketing after all. It is not so much the probability of failure that makes the difference,

2 99 Table 1 Prioritizing Consequences Consequence Very high High Moderate Low Plant/line downtime Major Minor None None OSHA/EPA Event Yes No No No Business interruption insurance Yes No No No Replacement lead time >90 days days days but the fact that the consequences from those failures, albeit still relatively small, are dramatically increasing in many cases. Consequences From Transformer Failures Table 1 provides a simple illustration of the consequences from transformer failure. While the best method for determining the consequence from failure is to monetize that consequence, it is often extremely hard to do. Consequences range from minor irritations to complete plant shutdowns that cost millions of dollars. Transformer Reliability Planning Clear standards exist for the chemical testing of transformer fluids; however, a great deal of discretion is applied to which transformers are tested and when. Coupled with advances in testing technologies and monitoring capabilities, far too much leeway is left in determining the best reliability plan for transformer fleets. Determining the consequences from potential failures is a good first step in determining the criticality of transformers. Fig. 1 outlines the potential steps in any reliability plan. While a basic plan might suffice for a <30 days small pad-mount transformer that powers the little-used back parking area, a more robust plan should be applied to a critical unit that might power a data center or a critical production component. Basic plans lead to the highest potential for unplanned outages. Assurance plans, while never guaranteeing that an outage will not occur, apply every possible measure to increase the detectability of a potential problem and are the most robust plans for critical units. Paper, Oil and Detectability Kraft paper is used to separate the copper windings in transformers, providing mechanical and dielectric strength and dielectric spacing. It is clear that the life of the transformer for the most part is based on the life of the paper. As the paper irreversably degrades, the reliability of the unit degrades. Dielectric fluids, the vast majority being mineral oils, act as a coolant, provide additional dielectric Figure 1 Reliability-centered maintenance scale.

3 100 Technical Article strength, protect the paper and play a tremendous role in detecting problems in the transformer. In fact, the first basic in transformer testing is diagnostic testing of the fluid. The same is true for FR3 or silicone testing in transformers that use these fluids as insulating fluids. Chemical testing is the accepted industry standard for detecting the reliability of a transformer. Consider that oil plus a catalyst like paper, copper and/or iron, coupled with an accelerator like heat and moisture, creates oxidation. Oxidation byproducts are numerous: Alcohols. Peroxides. Ketones. Aldehydes. Metallic soaps and epoxies. However, one byproduct of oxidation that degrades paper significantly is acid. Fig. 2 shows the acceptable to questionable to unacceptable levels of acids in four simple magnifications at 750x of acid in paper. For greater diagnostics, additional chemical testing includes: Liquid screen. Inhibitor content power factor. Karl Fischer (moisture). Gas in oil (dissolved gas analysis, DGA). Metals in oil. Furan. When appropriate, polychlorinated biphenyls (PCBs). Field Inspection The value of a simple field inspection is often overlooked when sampling transformer fluids. A good visual inspection should look for and document: Figure 2 At a 0.05 acid level, the beginning of a questionable acid level begins. Remember, paper degradation cannot be reversed so a questionable level should be the first sign that maintenance is required. At a 0.10 acid level, the beginning of an unacceptable result has been reached. The buildup of acid along the fiber strand and the beginning of splitting within the strand can be seen. At a 0.15 acid level, even more paper degradation and acid buildup can be seen. Fiber strands are breaking and acids continue to build up. Effects of acid on paper (magnified). At a 0.30 acid level, the paper begins to look more like porridge than paper. Much of the dielectric strength is lost and the life of this paper does not bode well for the reliability of this transformer.

4 101 Area accessibility. Paint condition. Gaskets. Bushings. Checking the readings and the working order of the gauges: Level gauge. Temperature gauge. Pressure/vacuum gauge. IR and Chemical Testing: Better Together While infrared (IR) testing is pretty standard for electrical systems, an annual IR test of the entire building is usually done and the test of the transformer is seldom correlated to the time a sample is pulled for chemical analysis. It has been found that conducting a thorough IR scan at the time the sample is pulled provides better information for the IR and better information for the oil analysis. The engineering team can better identify the cause of a hot spot picked up on the IR report if they have the chemical test available to review at the same time, so conducting both tests at the same time is highly beneficial. Another benefit of IR at the time of sampling is that the IR data can be housed with the chemical data. When there is an issue, it eliminates the need to search for two sets of data that do not really correlate due to the timing each test was conducted. What should one look for with an IR test on the transformer? Temperature under 65 C/55 C. Heat dissipation from the top of the transformer tank/radiator to the bottom of the transformer tank/radiator. Low oil level. Temperature difference between two similar bushings. Hot spots showing on tank, load tap changer (LTC) compartment, throat connections or bushings. the specifics of the diagnostic tests. As in the case for acids presented here, a level between 0.05 and 0.10 is questionable and a level above 0.10 is unacceptable. In any reliability program, when equipment reaches these levels, the computerized maintenance management system (CMMS) kicks in and the right parts, the right tools, and the right people arrive in time at the right place to avoid a failure. It is time those same reliability standards were applied to the electrical system. One of the difficulties in doing so is because most CMMS and enterprise asset management (EAM) program do not have built-in capability for transformers; therefore, a robust data management program needs to be initiated for transformer testing. What would a good preventive maintenance (PM) or predictive maintenance (PdM) program do? Vacuum processing/degassing. Reinhibiting. Moisture reduction. Hot oil clean. LTC inspection and repair. Recasketing. Refurbishing. Full electrical testing. A recent study looked at the impact of service on transformer life. Fig. 3 presents the results of that study of more than 1,500 decommissioned units. For those units in the study where no service (PM or PdM) was done, the units lasted just under 20 years, which is what the insurance industry and many OEMs have predicted. However, with just one service, that life extended to a little more than 27 years. For two services, the life extended to just under 35 years and finally at three services the life was just over 37 years. Basically, the life of a unit can be doubled by maintaining the oil, removing moisture from the paper, and doing basic connection or bushing repairs. Figure 3 Preventive and Predictive Maintenance One of the most disturbing trends relative to transformer reliability is the tendency to avoid any sort of maintenance on transformers other than reactive maintenance. Given the fact that as the paper degrades, the reliability of the unit degrades and this can never be reversed, it would seem logical to use diagnostic testing to determine the maintenance standards to be put in place. In far too many cases, when doing root-cause analysis of a failed unit, the condition of the equipment prior to the failure was clearly demonstrated as questionable to unacceptable two ratings used based on Average service life related to number of oil services performed: an SDMI study based on 1,534 decommissioned oil-filled transformers >500 kva.

5 102 Technical Article Beyond extending the life of the unit, a weaker transformer is at a greater risk from a fault caused either up-line or down-line. A well-maintained unit is more likely to survive these external faults than a poorly maintained one. Fault Gas Monitoring Transformer monitoring is a rapidly growing field. It is estimated that the market for DGA monitors will increase from US$113 million in 2012 to more than US$755 million in This includes expansion from predominantly utility and generation monitoring into wider and broader application throughout the power grid and into industrial application as well. It is increasingly common to purchase DGA monitors at the time of purchase of new transformers, and adding monitors to critical in-service transformers is becoming a significant component of transformer maintenance and reliability programs. DGA monitor manufacturers use many different technologies for the purpose of dissolved gas detection in active monitoring. The largest manufacturers predominantly use gas chromatography (GC), photoacoustic spectroscopy (PAS), solid-state (SS), thermal conductivity detector (TCD) or selective membrane (SM)-based sensors. These technologies have been in active use for several years, though GC is currently the only gas detection method referenced in IEEE standards for gases generated in oil-immersed transformers. 2 Other emerging DGA monitoring technologies include non-dispersive infrared (NDIR) and carbon nanotube (CNT). In an 18-month study, all major OEM monitors were included, which account for more than 95% of monitors in service. Over that period of time, faults were simulated and the monitors reactions were tested. The results are summarized as follows: 1. The monitors worked. While there were some differences in lead and lag times for gas detection, overall, DGA monitoring works well. 2. False positives were experienced, and customers who have installed monitors have also reported the same issue. It requires diligence in understanding the data, where false positives are ignored and a real issue is missed when it occurs. 3. Data management for monitor data can, in many cases, create data chaos, a word one monitoring customer used to describe his monitoring program. Add to the fact that most monitoring data is not correlated to the chemical, mechanical or electrical testing data, and one can see why data chaos might happen. In one instance, the customers must maintain Windows 95 to house his monitor data from one monitor. Imagine having multiple brands with multiple systems. 4. Hydrogen was present in every fault condition simulated, making it a very good, low-cost measure. Running a chemical DGA after an alarm can then determine what events took place, so combining the DGA with the hydrogen monitor is a very good and cost-effective step to transformer monitoring. There are certain transformer applications where multiple gas monitoring would be recommended based on the required need for a broad range of gassing conditions and for transformers with a very high consequence from failure. Case Study A global steel manufacturer made a significant commitment to establish a reliability culture across its organization. The following information provides a high-level overview of some of the strategies used to increase its asset reliability. Health Check of Operating Transformers: In 2012, a program to conduct an annual health assessment on critical operating transformers was initiated. The transformer health check had several objectives, including: Establishing current operating condition of the most critical transformers. Providing information to the business that would allow decisions to be made knowing the relationship between risk and reliability. Ensuring a reliable and tested spare would be available, if needed. Maximizing use of the best available technology for monitoring transformer health with the goals of: Forecasting potential problems early to allow for maximum amount of planning. Minimizing damage if an event did occur. Standardized testing and inspection procedures. Standardized fill and start-up procedures for critical transformers. Increasing focus at the plant level and sharing information across all plants. The philosophy of the health check is based on the concept of overlaying various predictive and preventive maintenance inspections to maximize the ability to forecast a potential failure. Real-time combustible gas monitoring is one of several projects used as a means to increase focus on these assets to ensure future reliability. A beta trial with SD Myers was initiated in 2014 for development of a comprehensive transformer management dashboard. This effort continues in 2015 and now includes key step-down transformers as well as a condition rating for electric arc furnace (EAF) and ladle metallurgy furnace (LMF)

6 103 spare transformers. Specific recommendations aimed at ensuring reliable operations were developed for each site as part of this assessment. Figure 4 Average Operating Critical Transformer Gas Content: One benefit of the yearly health check is a deeper understanding of quantities and types of key gases that may be found in EAF and LMF transformers. Interesting patterns have been detected not only in certain combinations of key gases but also in what may be considered typical based on specific brand and function. The average age of the transformers in the program was 23 years. Operating Transformers Without Strong Spare Protection (Excluding Untested Transformers) When considering reliability, another critical ingredient is the condition of spare transformers. If spare units are not tested and maintained to the same reliability standards, unplanned outages can be extended needlessly. The results of the health check for spare transformers are shown in Fig. 5. Tested Spare Effort: This program was put in place to ensure availability and integrity of critical spares for EAF and LMF transformers. Condition 1: Condition 2: Condition 3: Condition 4: Continue normal operation Continue normal operation Monitor at shorter interval Problem may be developing Determine TDCG rate Advise mill manager, manufacturer, corporate reliability manager Problem is developing or already exists Exercise caution Determine probable diagnosis Ensure transformer plan is documented Confirm spare availability Review trend data Advise mill manager, manufacturer, corporate reliability manager Extreme caution Advise reliability director Plan/schedule maintenance Corrective action recommended Site E (EAF) This spare is on-site. It was rebuilt in 2014 and installed in April Site D (LMF) This LMF transformer is on-site and was scheduled for installation in Site A (EAF) This new transformer and reactor will be on-site for installation in Site D (EAF) This transformer required repairs and will be installed after it is received to validate readiness in Site (EAF) This transformer required repairs and was installed after it was received to validate readiness in Site (LMF) This transformer was relocated and was scheduled for installation in Risk priority of ladle metallurgy furnace transformers based on condition. Site (LMF) This new transformer will be on-site for installation Site (EAF) Two EAF 93 MVA transformers are on-site. Both of these are smaller than the existing operating transformer. One is untested and the second is classified in condition 3 due to gassing issues. Installation of either of these two transformers would result in: Reduction in active power by 12%. Increase power-on time by 14 17%, relative loss of production. Slight reduction of electrical consumption.

7 104 Technical Article Table 2 Average Operating Critical Transformer Gas Content Year H 2 CH 4 Methane Ethane C 2 H 6 Ethylene C 2 H 4 Acetylene C 2 H 2 CO CO 2 N 2 O 2 TDCG , ,660 16, ,794 57,922 15, Moisture ppm Figure 5 EAF/LMF spare transformer condition rating based on IEEE C plan is current. Refinement and detailing of these plans continues across most sites. Sites indicated in red may have a plan; however, it has not been submitted or reviewed by the corporate reliability team. Installation of Kelman Real-Time Dissolved Gas Analyzers This effort was expanded to include all LMFs and will eventually include their associated step-down/regulating transformers. The project is ongoing and benefits have been significant in plants where units have been installed. Benefits include commissioning, trending and troubleshooting. The focus remains on ensuring that all plant EAF transformers have this capability installed. Increase in chemical usage due to a longer power-on time (liquid O 2, carbon and Fe). Increase in refractory and electrode consumption. EAF Transformer Exchange Planning Effort is aimed at ensuring that a document change-out plan is available for EAF transformers on a scheduled basis. Focus remains on ensuring documentation of the Data Management: The transformer health check effort has been successful at preventing unplanned critical transformer exchanges due to an unexpected failure for over 24 months. While the effort has been considered a success, the vision of having a real-time system capable of validating the health of a transformer on a daily basis remains the ultimate goal. The current program structure has several levels of monitoring that populate the SD Myers Transformer Dashboard. Table 3 Testing Projects by Site Projects Site A Site B Site C Site D Site E Site F Site... Site... Site... Site... Site... Tested spare arc furnace 2016 Tested spare LMF On-site spare requires repair Aug 2015 Apr 2015 N/A N/A / 2016 N/A 2015

8 105 Table 4 EAF Change-Out Days by Site Projects Site A Site B Site C Site D Site E Site F Site... Site... Site... Site... Site... Number of days estimated for EAF change-out 4 Data pending Data pending 5 7 Data pending 5 Data pending Table 5 EAF and LMF 8 Gas Monitors by Site Projects Site A Site B Site C Site D Site E Site F Site... Site... Site... Site... Site... Arc furnace Kelman LMF kelman Future Future 1 N/A Two on order installation 2015 Future N/A Future The first is at the site level, where the reliability engineer in conjunction with the maintenance system team monitors trends, schedules PM and PdM work orders per established guidelines, and ensures followup work orders are written for any deficiencies noted. This includes oil sampling at established frequencies based on type and function of transformer. The second line of defense is a comprehensive look at approximately 100 transformers considered critical to the business. This health assessment includes a comprehensive review of past year DGA trends, spares condition, location, electrical testing results, etc. The third level of monitoring is currently limited to EAF/LMF and critical step-down transformers. These sites have equipped transformers with GE Kelman dissolve gas monitoring systems that allow for real-time data to be acquired. Sites leverage GE Kelman alarming and notification systems in a variety of different ways; however, the primary advantage of Kelman is the ability to immediately detect a problem in a transformer prior to an event. In addition, it has been found invaluable as a quick check on start-up of new transformers or establishing conditions of transformers that experienced an event. Finally, a beta program with SD Myers was started in August 2014 that works toward establishing a comprehensive transformer database. This beta is providing on-line, real-time monitoring of the GE Kelman gas monitors on EAF and LMF furnace transformers. Information is available within the SD Myers dashboard, which is accessible from any location that has WiFi capability. There are currently six transformers from four different sites participating in this trial. This program will add a fourth line of defense in efforts to prevent an unexpected failure. Specific advantages of this concept include: Figure 6 Transformer Dashboard. One comprehensive database that has DGA results validated by a certified lab. Real-time information for the most critical transformers. Ability to store and organize electrical and mechanical test records. Ability to manage transformer PdM efforts through Dashboard. Accessibility via web for an unlimited numbers of users. Third-party support for detailed DGA analysis based on comprehensive dissolved gas database. Differential Protection: Differential protection, also known as Rogowski coil, is a technology capable of capturing a fault within two cycles of fault initiation. This technology is substantially faster than standard transformer protection. In situations where a flashover occurs on secondary, this type of protection can take a transformer off-line and minimize damage from this type of event. While it does not prevent a fault, it does mitigate damage to a minimum based

9 106 Technical Article Table 6 EAF and LMF Differential Protection by Site Projects Site A Site B Site C Site D Site E Site F Site... Site... Site... Site... Site... EAF differential protection and/ or Rogowski coil 1 1 N/A 1 LMF differential protection 1 1 N/A N/A PS in EPM PS in EPM 1 PS in EPM on the latest technology. This, in combination with a PM program that inspects other protection devices including Buchholz relay and sudden pressure relay, is the last defense in the event of a fault. This technology has been implemented at several mills. Documented instances where this protection system successfully prevented major damage are available. Technology was not fully developed for DC furnace applications in The health check has evolved with development of the transformer risk rating. This rating was developed to allow easier understanding of risk to business from these critical assets versus only health of a specific transformer. The model is in an early stage of evolution and will continue to be adjusted to be more accurate in coming years. Figure 7 Risk Rating: Considering all of the above factors, a risk rating was developed based on the following criteria: EAF versus LMF duty. Dissolved combustible gases. Oil condition. Spare condition. Spare availability. Fault severity. Current fault versus previous. Planning preparation. Age. Business impact (future). Electrical testing (future). Critical transformer risk rating. Based on the above risk rating, specific detailed site recommendations have been developed. Additional Maintenance Activities for Critical Transformers in Operation During the retrieval of the oil sample, it is recommended that the following PM and PdM activities be coordinated at the same frequency to help more accurately define the health of the transformer: Thermography scan of transformer, cooling and diverter pump loops, and complete visual inspection of transformer, including check of transformer temperature gauges, levels and general condition. Transformer grounding connections check. Visual inspection for any signs of leaks. Update and review historical records in CMMS for tap changer selector, diverter and control (mechanical drivetrain).

10 107 Over the past several years, there have been about 50 failures of large transformers worldwide due to corrosive sulfur in oil. Sulfur compounds in the oil can be very corrosive and attack copper conductors. It is recommended that transformers at risk (filled within past 10 years, high operating temperatures and/or high electrical stresses for extended period of times) have D1275 Method B completed. Electrical Testing Required for EAF Transformers in Operations EAF transformers that are in operation are considered critical to business and as such require electrical testing as outlined below. Testing frequency is every three years and recommendations of specific test are as follows: Perform insulation resistance tests, winding to winding and winding to ground. Perform transformer turns ratio test between windings on all taps. Perform winding resistance test between windings on all tap positions. Insulation power factor (Doble test). Core ground resistance (>200 megohms with 1,000-volt Megger). Transformer protection device testing as applicable, including: Buchholz relay. Sudden pressure relay. Liquid temperature alarm and trip setting (main tank and LTC). Winding temperature alarm and trips settings. Oil level alarms and trip settings. Hot collar test. Tap changer test as required by OEM. Transformer Maintenance Guidelines to Prevent Flashovers All maintenance plans should be detailed in the CMMS system with a task list detailing steps required to ensure EAF vault environments remain clean and free of contaminants that may results in flashover on the secondary buss work and associated bushings/ delta components. Contamination buildup on electrical components can occur in any high-voltage substation or EAF vault. Depending on the resistance values of contaminants, tracking and, in more extreme cases, arcing can occur. When contaminations form a bridge of conductive material over insulators, the high-voltage electricity can find a path to ground or phase-to-phase resulting in significant damage. Numerous documented cases exist in the steel industry where the root cause of the flashover was determined to be dust. Differential protection systems offer a last line of defense and may significantly minimize damage by taking the transformer off-line much faster than standard transformer protection. It should be noted that thermography and visual cameras provide an extremely limited warning of this type of event. They can help in the analysis of where the fault first occurred. Guidelines for Filling and Start-Up of Critical Transformer A defined process for filling and energizing new or rebuilt critical transformers is essential when installing a critical spare transformer. Installation should be completed as soon as possible to validate readiness during the manufacturer s warranty period. Untested transformers are classified at condition 3 in the health check. In addition to normal electrical testing required during installation of a new or rebuilt transformer, there are specific guidelines developed around insulation fluid fill that must be followed prior to energizing the transformer. Conclusion To nominate this paper for the AIST Hunt-Kelly Outstanding Paper Award, visit AIST.org/huntkelly. Tools are available to significantly impact the reliability of electrical systems. Due to the aging nature of existing transformers and the unique design and manufacturing changes for new units, every company must determine what its standard of reliability will be. An analysis of the consequences from failures coupled with the best detectability standards will mean less unplanned downtime, a more reliable and low-cost system, and the assurance and peace of mind that comes with instituting and maintaining the best practices for transformer reliability. The integration of chemical, mechanical, and electrical testing and critical unit fault gas monitoring gives the information necessary to make wise and timely operating and capital decisions provided that information is easily accessible and shared appropriately. F This paper was presented at AISTech 2015 The Iron & Steel Technology Conference and Exposition, Cleveland, Ohio, USA, and published in the Conference Proceedings.