POWER TRANSFORMER CONDITION MONITORING AND ASSESSMENT FOR STRATEGIC BENEFITS

Muhammad Arshad and Syed M. Islam

Curtin University of Technology

Department of Electrical & Computer Engineering, Perth, WA 6845, AUSTRALIA

Abstract Power transformer is a complex and critical component of the power transmission and distribution system. System abnormalities, loading, switching and ambient condition normally contributes towards accelerated aging and sudden failure. In the absence of critical components monitoring, the failure risk is always high. For early fault detection and real time condition assessment, online monitoring system in accordance with age and conditions of the asset would be an important tool. After being indicative of abnormality it is important to carry out offline tests/ diagnostics to ascertain the overall integrity and assessment to avoid unscheduled outages, financial/ revenue losses and environmental/ collateral damages. This paper discusses condition assessment criteria based on asset abnormalities with respect to age and a case study, asset being indicative of some abnormalities with 87.30% peak loading.

1. INTRODUCTION Insulation is the major component, which plays an important role in the life expectancy of the transformer. Transformer life known to us is based on the designed parameter with respect to normal operation and climate conditions. To determine the performance and aging of the asset, insulation behavior is a main indicator [1]. Most of the transformers in a system, around the world are exceeding their designed life. In the absence of insulation assessment, good number of transformer failed due to insulation problems, before reaching to their designed technical life. It is important to investigate the cause(s) of the insulation degradation with respect to age. Average age of the transformers that failed due to insulation deterioration during the last ten years was 17.8 years [2]. A good number of aged transformers are still performing well, it is vital to monitor the insulation behavior rather then replacing with new one. Transformer insulation behavior is different with respect to operation mode, climate (ambient condition) and frequency of subjected faults. Load growth has influence on the insulation degradation. The insulation degradation trend needs regular assessment. An accurate analysis of the insulation can suggest operating condition, de-rating of the transformer will increase the life expectancy [3, 4].

The unit can be proposed for relocation, subjected to less stress. Cost effective maintenance strategies can be developed. Insulation aging in transformer is a complex and irreversible phenomena. To ensure higher reliability and safety, insulation condition monitoring and trend analysis are of major concern. Insulation trend analysis will conclude type of failure as well as severity of the fault. This will make easy to understand type of maintenance required, loading constraints and future management required. The analysis will predict the life expectancy of the asset. It is significant to recommend insulation assessment for the aged and suspicious behavior transformers. With perfect condition monitoring the rate of aging can be reduced. Online insulation condition monitoring, proper diagnostics and accurate interpretation/ analysis will provide realistic decision for economical operation and cost effective maintenance strategies. The overall integrity of the asset can be assessed, with minimum risk of sudden failure. The environmental risk can be reduced. Effect of aging rate on the life expectancy can be established. Condition monitoring provides information on the developing insulation problems and incipient faults [5, 6]. Thus early warning of any abnormality can avert the catastrophic failure.

2. TRANSFORMER ASSESSMENT Since 1885 transformers (0.15 MVA) are serving the power industry and are being produced with higher rating (> 2000MVA). Majority of transformer population is serving in many of the transmission and distribution utilities are 20 to 40 years old. As an example the installed power transformer (United States) capacity has reduced from 185 GVA (Giga Volt Amperes) to 50 GVA per year over the past twenty-five years [7].

The average load growth rate observed is approximately 2% [7]. Transformer utilization has increased by 22% on average, causing oil hot spot temperature to increase by approximately a 48%, at normal peak load [7, 8]. Due to gradual increase in the temperature, peak load insulation life will be reduced by a factor of approximately 8 [7, 9]. Economic pressures and factors such as an increasing proportion of aged power transformers are combining to dictate more efficient plant maintenance management.

Life assessment is becoming increasingly important as the average age of the asset increases, due to economic pressures and a relatively low load growth, with fewer major re-development projects.

A scientific remnant life assessment would be an important tool towards higher reliability of the system and asset management. After determining the critical indicator responsible for aging as well as asset technical assessment, the rate of ageing can be reduced by implementing the correct operational and maintenance strategies. The early and failures due to aging can be effectively minimized. Better asset management system can be implemented (timely relocation/ replacement can be planned). The transformer's condition assessment can be broken down into the following areas of concern:

• Operating performance to design criteria • Aging of insulating materials due to stress

imposed both thermal and electrical. • Chemical deterioration from moisture, oxygen

and acidity and other contaminations. • Mechanical strength of the solid insulating and

bracing materials. Transformer assessment is mainly based on dissolved gas analysis (DGA), in particular Rogers Ratio method [12, 13]. C2H2/C2H4, CH4/H2 & C2H4/C2H6

The important issue is trending of combustible gases.

TVSS

R OT

×××−

=−

5.710)( 6

Where, R = Rate (ft3/day) SO = First sample (ppm) ST = Second sample (ppm) V = Tank oil volume T = Time (days)

The other important parameter is rise in winding and top oil temperature. The analysis outcome mainly depends on the test accuracy and correct interpretation [12, 13]. 2.1 Critical Components Core, windings, insulation oil, bushing and on-load tapchanger are the main active parts of the transformer insulation chain [10, 11]. The degradation of insulation systems is accompanied by phenomenon of changing physical parameters or the behavior of insulation systems. The degradation of insulation systems is a complex physical process. Many parameters act at the same time thus making the interpretation extremely difficult [13, 14]. The aging process in the oil/cellulose insulation system under thermal stress and their measurable effects are due to chemical reactions in the dielectric. The temperature of the oil/paper dielectric is the critical aging parameter to cause enough change in the mechanical and electrical properties of the material. Apart from high temperatures, other important parameters affecting the aging of the solid and liquid insulation include the presence of water and oxygen in the system [6, 7]. The monitoring and assessment of such components is vital to achieve better reliability of the system. By implementing correct operational and maintenance strategies the insulation aging/ degradation process can be controlled and the asset life can be extended effectively. Asset’s critical component monitoring (strict) is required for the technical assessment (normal to end of life) to ensure economical and safe operation. Also better asset management polices can be implemented [15]. 2.2 Major Failures The types of failures which may occur within the transformer tank are many, one with serious concerns to

identify the effectiveness of diagnostics tests and various condition monitoring techniques are listed below [3, 10]: 2.2.1 Core Overheating breakdown in core plate insulation leads to circulating currents and usually sparking at the fault. 2.2.2 Core bolt and Core clamping structure Breakdown of insulation between parts of clamping structure results in circulating current, possibly sparking. Breakdown of insulation between core and core clamps and the tank leads to spark (fault). 2.2.3 Windings and inter-winding insulation Overheating due to poor joints is a common fault in any part of the electrical circuit. Breakdown of inter-strand insulation results in circulating current causing overheating of insulation and hot spots at point of fault. This can be a result of winding movement. A turn to turn fault produces a similar effect but with much more energy and can usually be detected and identified, whereas there is currently no diagnostic test to identify a strand to strand fault. Partial discharge faults can develop between various parts of the insulation structure as a result of contamination (including moisture) or due to poor impregnation or overstressing. Overheating of stress shields results in breakdown and circulating current. A fault between windings - usually results in serious damage and a fault from line to ground also usually results in serious damage. 2.2.4 Tank, flux shields, and fittings The breakdown of insulation between portions of the tank shields or between the shields and tank can lead to circulating current, this will be a function of load current. Partial discharges may emanate from the ground potential surfaces of the tank and parts mounted on the tank. Circulating current in the tank due to proximity of heavy current conductors can produce hot spots in the tank and across gasket joints. 2.3 Deterioration and Failure Factors The factors responsible for failures and accelerated deterioration are categorized as [3, 11]:

Operating environment (electrical) Operating voltage (50/60 Hz), transient over-voltages, load current, short circuits (fault currents), lightening and switching surges. Operating environment (physical) Temperature (operating full load with high ambient temperature-humidity index), wind, rain, seismic and pollution. Operating time Time in service and time under abnormal conditions or extreme condition (Load variation, change in thermal stresses). Number of operations of tapchanger Number of on-load tapchanger operation.

Vibration effect Sound and material fatigue.

Contaminants Moisture (water content in oil), presence of oxygen and particles in oil. 3 A CASE STUDY In service transformer (132/33 kV, 60 MVA,) was investigated for its abnormal routine dissolved gas analysis behavior. Unit was commissioned in 1981 and first oil was sampled for DGA in 1996 [Table 1]. The key combustible gases (C2H2 & H2) were found in higher concentration. According to the limits described in the IEEE guide for interpretation of gases, the transformer total dissolved combustible gas (TDCG) exhibits normal conditions [16, 17]. C2H2 & H2 identify IEEE condition two [Figure 1 & Table 1]. This shows that an active fault (early) is present. No further investigations carried out except the transformer oil was reprocessed and the unit was energized.

Gas (ppm) H2 O2 CH4C2H2 C2H4C2H6 CO CO2 N2

21.10.96124.716223.3 9.9 47.0 15.3 8.2 242.84026.052222

23.10.96 73.3 17409.8 9.6 46.3 15.2 7.9 232.63911.95101512.3.97 3.8 12683.2 2.0 8.8 5.2 3.2 23.4 902.4 30957

5.11.97 21.4 19037.4 5.0 10.9 6.3 3.8 157.21906.650372

17.3.99 26.6 19616.3 9.7 47.9 17.9 7.8 150.42208.253939

Table 1 Dissolved gas analysis (DGA)

Combustible Dissolved Gas Concentration

0100200300

H2 CH4 C2H2 C2H6 CO

Gas

ppm

21.10.96 23.10.96 12.3.975.11.97 17.3.99

Figure 1 Transformer DGA Characterisitcs

The unit was tested in early 1997 and found DGA with in the limits. A DGA was conducted again in the December 1997 which shows some trending in C2H2 and CO which show the presence of a thermal fault. The oil was last sampled in 1999, which conclude fast trending of C2H2. The unit was serving with 87.30 % peak load [Figure 2]

Transformer Peak and Off-Peak load Curves

0

50

100

150

200

250

Jan

Feb

Mar AprMay Ju

n JulAug Sep Oct Nov Dec

Months

Ampe

res

Peak Load (Amp.) Off Peak Load (Amp.)

Figure 2 Transformer Loading Curves

Due to the load growth of the area the unit at present is serving very close to the full load operation. The region has high temperature and humidity index [Figure 3] and remains always a contributing factor in accelerated aging of the asset. The peak load and winding temperature characteristics are given in figure 4. The unit winding temperature at peak load is around 90 degree centigrade with an

average summer ambient temperature of 47 degree centigrade and relative humidity 70% to 86%. In the absence of asset technical assessment, failure risk stands high.

Average Ambient Temperature & Relative Humidity

0

20

40

60

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Months

Tem

pera

ture

(deg

. C)

0

10

20

30

40

50

60

70

80

90

Him

idity

(% R

H)

Max. Temperature (°C) Min. Temperature (°C)Max. Relative Humidity Min. Relative Humidity

Figure 3 UAE Temperature & RH Profile

Peak Load & Winding Temperature

0

50

100

150

200

250

1 6 11 16 21 26 31

Days (August)

Amps

.

0

20

40

60

80

100

Deg.

CLoad Temperature

Figure 4 Summer Peak Load and Winding Temp.

An experience based approach was made and the unit was restricted to 70% loading with monthly oil sampling to accommodate the summer load. The initial three oil samples show no fast trending for any key combustible gas. The winding and top oil temperature is well with in the limits. Unit is scheduled for diagnostic test in off peak season. The unit is being strictly monitored for any abnormality. The cooling system is also under surveillance.

3.1 Condition Assessment Levels An accurate condition assessment and appropriate action to the abnormality will restrict the premature failures (catastrophic). The asset’s life could be extended by implementing reliability centered maintenance. Based on transformer population survey and respective condition evaluation (new and serving close/ beyond design life) the following recommendations were made to avoid failures [19, 20]. 3.1.1 Transformer operating with in their design

life. The following levels classified are based on the abnormalities related to the “condition assessment factors”.

Level 1 Abnormalities below the limits: Recommended for full load operation with routine monitoring and checks.

Level 2 Abnormalities just above normal limits: Recommended full load operation with routine monitoring including top oil temperature, winding temperature and DGA.

Level 3 Slow DGA trending with increased top oil and winding temperature: Recommended 80 – 75 % of the rated load operation with strict monitoring of top oil temperature, winding temperature, DGA and trending analysis. Perform offline diagnostics and develop maintenance strategies accordingly.

Level 4 Fast DGA trending with increased top oil and winding temperatures: Recommended 50 – 60 % of the rated load operation with strict monitoring of top oil and winding temperature, DGA for total combustible dissolved gas and rate of gas evolution (trending). In the absence of online DGA, the oil sampling frequency should be at least once a month. Arrange for emergency offline diagnostics and maintenance accordingly. Keep under strict observation. Plan to relocate the asst. 3.1.2 Transformer operating beyond their design life. Level 5 Abnormalities below the limits: Recommended for 80 % of the rated load operation with routine monitoring and DGA frequency twice a year.

Level 6 Trending abnormalities (trace): Recommended 60 -70 % of the rated load operation with strict monitoring of top oil temperature, winding (hotspot) temperature and dissolved gas analysis (DGA) frequency once every three months, online DGA application is worth.

Level 7 Fast DGA trending (evolution rate higher then 0.1 ft3/day) with increased top oil and winding temperature: Recommended 50 % of the rated load operation with strict monitoring of top oil temperature, winding temperature and DGA trending. Arrange for emergency off-line diagnostics and maintenance accordingly. Plan to replace the asset. 4. CONCLUSION According to Australian CIGRE Panel 12 Annual Reliability Survey the average age of transformer population (66 kV, 10 MVA and Above) in 1995 in the participating utilities in Australia and New Zealand is 28.6 years, with a considerable number of transformer over 40 years. At present the Australian national average age for power transformers is around 32 years. With strict monitoring, accurate diagnostics interpretations and realistic operational/ maintenance strategies implementation the following would be achieved effectively:

• Asset economic loading conditions identification and assessment for maximum practicable operating efficiency.

• Premature failures risk minimisation. • Remnant life estimation and timely asset

replacement/ retiring planning. • Asset life extension by implementing correct

operational and cost effective maintenance strategies

• Improvement in the system performance ensuring good reliability as well as plant availability.

• Minimization of the long-term operational cost. • Cost saving by eliminating the unplanned

maintenance. • Minimizing the outage period. • Relocation/ retirement planning. • In time procurement of spare parts to get

competitive rates. • To enhance the over all reliability of the system • Accurate risk assessment.

• Effective asset management strategies. • Low insurance premiums. It will also benefit the end user to have power supply with out interruption, in particular the industrial sector. It will reduce the risks to human kind and the environmental damages.

4. REFERENCES [1] Transformer insulation behavior during over

load, V.G Davydov, O. M. Roizman, W. J. Bonwick, Centre of electrical power engineering, Department. Of Electrical & Computer Engineering, Monash University

[2] An Analysis of Transformer Failures, Part 1 & 2-1988 through 1997, By William H. Bartley.

[3] Insulation condition Monitoring and Reliability cantered Maintenance of Electrical Plant, Short course & workshop 24-26 February 1997, Monash University

[4] Power transformer condition monitoring – Pacific Power International and University of Newcastle Developments. S.M. Islam

[5] Reliability centered maintenance, Bruce T. Kuhnell, centre of machine condition monitoring, Monash University, Melbourne, Australia.

[6] Condition Monitoring and Life Assessment of Aged Transmission/ Sub Transmission Plant (Part A & B), D. Allan, Powerlink Queensland

[7] Power transformer design enhancements made to increase operational life by David j. woodcock Jeffrey C. Wright, P.E, Weidmann Technical Services Inc.

[8] IEEE/ANSI C57.91 – 1996, “IEEE Guide for Loading Mineral-Oil Immersed Transformers”.

[9] IEC 354: 1991, “Loading Guide for Oil-Immerse Power Transformers”.

[10] In service condition monitoring of power transformer, Fred, Fetherston, Pacific Power International, June 1996

[11] Insight into condition monitoring trends. Mark Cotton, Technical services, PowerNet

[12] IEEE Std. C57.96-1999, IEEP guide for loading Dry type distribution and power transformers, Transformer committee of the IEEE power engineering society, IEEE-SA standards board, 26, June 1999.

[13] M. Arshad, S. Islam, Transformer reliability enhancement using online dissolved gas monitoring and diagnostics, IPEC, Singapore, 2003

[14] Fuzzy diagnosis of transformer incipient faults, Lecture notes for the 1997 short course on ICM & RCM at Monash University, Q. Su, Centre for Electrical Power Engineering, Monash University.

[15] Experienced-based Evaluation of Economic

Benefits of On-line Monitoring Systems for Power Transformers. S. Tenbohlen, T. Stirl, G. Bastos, J. Baldauf, P. Mayer, M. Stach, B. Breitenbauch, R. Huber. Cigre, 12-110 session 2002

[16] Transformer committee, “IEEE guide for the interpretation of gases generated in oil immersed transformer”. IEEE Std. C57.104-1991, IEEE PES

[17] IEEE and IEC “Codes to interpret incipient faults in transformer”, using gas in oil analysis by R. R. Rogers C E G B Transmission division. Guilford, England, Circa 1995.

[18] Pennsylvania - New Jersey - Maryland interconnection planning and engineering committee transmission and substation design subcommittee, transformer rating task force, Feb.1999

[19] Paper presented at the EPRI “Substation Equipment Diagnostics Conference IX” February 18 -21, 2001 New Orleans, Louisiana, USA

[20] Power transformer design enhancements made to increase operational life by David j. woodcock Jeffrey C. Wright, P.E, Weidmann Technical Services Inc.