DEFERRING REPLACEMENT OF A 600 MVA, 345GRD Y/138GRD Y/ 13.8 kv SHELL TYPE WESTINGHOUSE AUTOTRANSFORMER

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1 DEFERRING REPLACEMENT OF A 600 MVA, 345GRD Y/138GRD Y/ 13.8 kv SHELL TYPE WESTINGHOUSE AUTOTRANSFORMER JESSE M LOPEZ CPS ENERGY USA EMILIO MORALES CRUZ QUALITROL USA SUMMARY Power transformers are essential components of transmission systems and often the most valuable asset in a substation. This 600 MVA autotransformer is the second oldest autotransformer in CPS Energy fleet. It is connected in parallel with a higher impedance autotransformer; therefore, it sees more load than its counterpart and has a combustible gas generation history. These conditions made this autotransformer the most logical candidate for replacement, but the high capital cost for a new unit requires further analysis to justify its replacement. A condition assessment was performed and indicated that the autotransformer could continue in service for more years. So, the concern then became the autotransformer's reliability. An approach to address this reliability concern is to provide a method for early detection of incipient faults. On-line monitoring provides visibility of issues earlier, reducing the risk of unexpected failures and unscheduled outages, thus raising the reliability to an acceptable level. This paper presents the results of the comprehensive condition assessment carried out, the financial benefits and consequence of deferring this autotransformer replacement, and an evaluation of the economic contribution that could be expected from on-line monitoring. KEYWORDS Transformer, Condition, Assessment, Reliability, Detection, Incipient Faults, Risk, On-line, Monitoring, Benefit. INTRODUCTION CPS Energy is the largest combined electric and gas municipal utility in the United States. It is whollyowned and regulated by the City of San Antonio, Texas, serving the residents and businesses of San Antonio and adjacent municipalities that contracted with CPS Energy for utility service. CPS Energy serves a base of 741,000 electricity and 331,000 gas customers in a 1,566 square mile service territory that 1

2 includes Bexar County and portions of Atascosa, Bandera, Comal, Guadalupe, Kendall, Medina, and Wilson counties. CPS Energy Asset Management s purpose is to systematically derive the highest value from facility assets through a consistent philosophy, realistic objectives, deliberate plans, and cooperative involvement by all stakeholders. The asset management policy guides how CPS Energy manages the replacement and maintenance of power transformer equipment and related components. The purpose of this policy is to ensure that replacements and new purchases are made in accordance with a consistent, approved approach that prudently manages expenditures for these assets. Power Transformers are one of CPS Energy s largest distribution capital assets. A typical power transformer serves an average of 3500 customers and supports 4 distribution feeders. There are currently 220 power transformers in the CPS Energy system, with an anticipated design life of 50 years. CPS Energy utilizes a replacement strategy of approximately 4 power transformers per year, in order to sustain a 50 year life cycle and to avoid an unmanageable number of replacements over time. The Transmission and Distribution System Long Range Plan provides a 1-5 year system infrastructure development plan based on analyses of current system performance and forecasted future requirements. The projects in the plan address anticipated and forecasted load growth, aging infrastructure, and reliability enhancements. One of these projects identified an autotransformer as part of the Infrastructure Modernization capital replacement program. The replacement justification was that the unit had been in service for 35 years and showed dissolved combustible gases. The age and combustible gases indicated the autotransformer could experience a premature failure, and cause outages. Replacing this unit would avoid unexpected failure due to age and condition, reduce the risk of failure well into the future, reduce maintenance expenses, and increase system reliability. Due to the high capital cost of this unit, a more substantial justification was required, so a condition assessment was conducted on this autotransformer. CONDITION ASSESSMENT The condition assessment consisted of a review of the operating condition records and electrical and chemical tests, some of which were performed during planned outages. The test lead to a diagnostic analysis of the insulation's condition and external components such as the load tap changer, bushings, cooling equipment, control and protection gauges, gaskets and tank inspection for leaks. Insulation Life Assessment Because there were no records of loading conditions, hot spot, top oil and ambient temperatures, a conservative insulation life assessment was performed using OEM available data (nameplate and test report), loading and ambient temperature records and dissolved gas analysis (DGA). Since aging or deterioration of insulation is a time function of temperature, moisture content, and oxygen content, the following assumptions were made during the assessment: 1. Normal insulation life of years was used considering a 65 C average winding temperature rise insulation system at the reference temperature of 110 C. [1] 2. Test report didn t provide the values used to calculate the hot spot temperature gradient, therefore a value of 30 C was used for the hottest winding (common winding) at 600 MVA and maximum load losses. 2

3 3. Top oil rise of 49 C from the OEM heat run test data at 321 MVA (ONAN) and maximum losses tap position. 4. A maximum average load experienced by the autotransformer (connected in parallel with a higher impedance unit) of 246 MVA at 345 kv 138 kv since 1979 (35 years). This value as a constant load was used for the insulation life assessment. 5. Same no load losses value since volts/turn is constant through the tap range. 6. ONAN cooling class operation, no cooling equipment has operated at 246 MVA. 7. Record high average ambient temperature of 90 F (32 C) recorded on August This extreme average ambient temperature was used for the insulation life assessment. 8. No moisture and oxygen contributions to insulation deterioration were considered, because both parameters were maintained well below their limits. 9. The transformer was installed in 1979 ( 35 years in operation). Using the IEEE Guide for Loading Mineral-Oil-Immersed Transformers [1], the calculated percent loss of life of insulation at the hottest spot over 35 years of operation was no more than 5%. The analysis was done considering extreme conditions like maximum recorded average temperature and continuous operation at 246 MVA. Dissolved Gas Analysis (DGA) The CO2/CO ratio from the DGA didn t show an abnormality degrading cellulosic insulation with a value greater than 7, which indicates a normal thermal decomposition of cellulose [2]. The other gases indicated a possible thermal fault of <300 C with individual and total dissolved combustible gases (TDCG) not exceeding condition 1 when the transformer condition was evaluated using individual and TDCG concentrations [2]. Also, the gases have been stable since June Therefore, the DGA indicated the transformer was operating satisfactorily. Load Tap Changer (LTC) The autotransformer was provided with a LTC UTH manufactured by Westinghouse in the mid-1970s. The LTC hasn t received an internal inspection during the last 15 years due to its lack of operation over many of those years. Most tap changers are set to automatic change mode. But this LTC is only manually operated when needed by the operations center control. The DGA also indicated the LTC was operating satisfactorily. Some issues associated with this tap changer include the mechanism freezing up causing non-operations in the time of use and oil seal issues where the seals are deteriorating on the back panel barrier board between the LTC and the main transformer tank. These issues could cause the LTC not to operate during maintenance testing and cause a decrease in the LTC's oil level; however the LTC has not experienced either of these issues. This tap changer is overbuilt and robust, but is becoming obsolete considering its age. There is limited service support. Although some replacement parts are available, most parts are not normal stock items. Most of the transformers with the UTH tap changer have been replaced or are moving towards replacement. It is recommend that if this transformer is left in service over the next few years, tap changer contact parts should be purchased in advance so they are readily available when needed for quick repairs. 3

4 Bushings The autotransformer was provided with Westinghouse bushings manufactured in The bushings have been exposed to the same loading conditions of the autotransformer experiencing similar insulation loss of life. The bushings are tested annually and only the neutral bushing is showing a deteriorating trend of its insulation. Cooling Equipment Control and Protection Gauges The cooling equipment control and protection gauges were inspected and tested. The test results indicated they are operating satisfactorily. Gaskets and Tank Inspection for Leaks The gaskets and tank inspection showed some oil leaks, which typically does not cause a major issue. However, the leaks will be addressed for long term care during the next maintenance outage. Condition Assessment Outcome The condition assessment indicated that the autotransformer was operating satisfactorily and could continue in service. Consequently, it was decided to extend its service life for at least another 5 years, provided that certain maintenance issues are addressed, such as replacing the neutral bushing and stopping the oil leaks. After conducting a thorough assessment of the transformer's condition, the issue then became whether it is reliable AUTOTRANSFORMER RELIABILITY [3] The primary risk of not replacing the transformer is the risk of unexpected failure resulting in unscheduled outages and unserved load. If the failure is catastrophic, it could cause fire and collateral damages such as property damage and environmental contamination. There is also a lead time for procuring replacement autotransformers. If the transformer is replaced on a reactive basis, significant cost increases occur due to the unplanned event. To reduce the risk of unexpected failure and a subsequent unscheduled outage, on-line monitoring can be used to continuously assess the condition of the transformer and timely detect an incipient fault. Transformer monitoring provides continuous condition assessments of developing incipient faults in the transformer. To achieve this, several diagnostic methods have been developed such as; dissolved gas analysis (DGA), partial discharge (PD) detection, bushing capacitance and power factor, transformer temperatures, load current, moisture in oil, and fun/pump current and operations. On-line application of these methods provides detection of anomalies, problem identification and a severity assessment of the condition, which all improve the autotransformer's reliability. If half of the major failures can be avoided and converted to minor failures, reliability is enhanced and the transformer can be allowed to serve for a few additional years before an unacceptable level of unscheduled outage probability is reached (see Fig. I). Fig. I. Effect of monitoring on transformer life duration 4

5 CPS Energy's transformer failure rate is about 0.29% excluding failures detected using existing means such as gas accumulation relay, top oil and hot spot temperature indicators, periodic inspections and oil sampling for DGA. A portion of these faults which are not detected by existing means could be detected with on-line monitoring. Detection efficiency varies based on the type of monitoring system deployed. It is unrealistic to expect a 100% detection efficiency. Some faults can go undetected or develop at a rate too fast to allow for proper alarming and orderly removal from service, they include those that are instantaneous by nature, e.g. an insulation breakdown following a lightning surge or a severe short-circuit. Moreover, some components such as bushing shields are prone to sporadic failures that may occur without warning. As a result of this analysis, assuming 60% detection efficiency (see fig. II), on-line monitoring caused the autotransformer failure rate to decrease from 0.29% to 0.12%, which is a reliability improvement of about 60%. Fig. II. Breakdown of failure probability FINANCIAL BENEFIT [3] The capital cost of a new/replacement 600 MVA autotransformer, including the cost of removing the old transformer and installing its replacement, is about $6,500,000. The benefit from deferred replacement is directly proportional to the current interest rate and the capital cost of a new unit. Therefore the value of deferring replacement at an interest rate of 6.75% is worth $438,750 per year. Over a 5 year period, the 5

6 savings is $2,193,750. The cost of a comprehensive monitoring system, considering the cost of the system, infrastructure installation costs and the yearly operating cost, is approximately $170,000. Without considering other benefits, such as reduced inspection and maintenance costs and reduced failure-related repair or replacement costs, the estimated total financial benefit is $2,023,750 over five years. Additionally, at the end of the 5 year deferral period, a new condition and reliability assessment could be conducted to determine whether additional deferral is possible, or the monitoring system could be repurposed and placed on another unit. CONCLUSION Because of a successful condition assessment, an increase in reliability and a substantial financial benefit, this analysis supports deferring the replacement of this autotransformer and applying a comprehensive monitoring system. The study also suggests that monitoring systems may be useful in other applications and should be considered when managing the replacement and maintenance of power transformer equipment and related components. BIBLIOGRAPHY [1] IEEE Std. C IEEE Guide for Loading Mineral-Oil-Immersed Transformers [2] IEEE Std. C IEEE Guide for the Interpretation of Gases Generated in Oil-Immersed Transformers [3] IEEE Std. C IEEE Guide for Application for Monitoring Equipment to Liquid- Immersed Transformers and Components 6