Smart Grid Monitoring of Transformers by DGA. Michel Duval. CIGRE Thailand, Bangkok 2013

Transcription

1 Smart Grid Monitoring of Transformers by DGA Michel Duval CIGRE Thailand, Bangkok

2 Electric Power 2

3 Power Transformers 3

4 Catastrophic Failures 4

5 Failures in Service - The failure rate of power transformers in service (internal failures needing repairs) typically is 0.3% per year. - For a population of 2000 transformers, this means 6 transformers will fail in the next year. - Less than 1 will fail catastrophically will not fail (i.e., 10% of the population at or above IEEE/IEC condition 1) will form abnormal amounts of gases because of faults. 5

6 The Monitoring Dilemma - Nobody knows which 6 of the 2000 transformers will fail next year. - To identify them, all the transformers need to be monitored, including the 1800 operating normally, just for the purpose of detecting the 6 that will fail and need repairs and the less than 1 that may eventually fail catastrophically. - In economic terms, the cost of monitoring is justified as long as it does not exceed the cost of not detecting the 6 failures and the catastrophic one (typically, >20M$). 6

7 Smart Grid Monitoring - A smart grid is a modernized electrical grid that uses information and communications technology in an automated fashion to improve the efficiency, reliability and sustainability of the production and distribution of electricity. - It implies a re-engineering of the electricity services industry. - It requires monitoring tools for evaluating on a real-time basis the condition of electrical equipment, so as to optimize asset utilization, system reliability and load capabilities 7

8 Monitoring Tools -General tools for monitoring oil temperature, oil pressure, partial discharges, etc, in transformers are available. -However, for the early detection of faults and failures and evaluating the condition of transformers, the main monitoring tool is dissolved gas analysis (DGA). -More than 1 million DGA analyses are performed by ~600 laboratories and ~ 40,000 on-line gas monitors each year worldwide. 8

9 Basic Types of Faults Detectable by DGA -PD: partial discharges of the corona-type in voids in paper insulation, as a result of poor drying or impregnating with oil. -D1: low-energy discharges, such as partial discharges of the sparking-type in oil or paper, tracking on paper, small arcing, arc-breaking activity in LTCs. -D2: high-energy discharges, e.g., flashovers, high-energy arcing, short-circuits with power follow through, with Buccholz alarms and tripping. 9

10 Basic Types of Faults Detectable by DGA -T1: thermal faults of low temperature T < 300ºC, because of overloading, insufficient cooling, design problems. -T2: thermal faults of 300 <T< 700ºC, because of defective contacts, welds, with carbonization of paper. -T3: thermal faults of high temperature T >700ºC, because of high circulating currents in core and coil, short circuits in laminations, often in oil only. 10

11 Additional Sub-Types of Faults Detectable by DGA -S: stray gassing of oil (in oil only) at T <200ºC, because of the chemical instability of oils produced since ~ O: overheating of oil or paper at T <250ºC, therefore without carbonization of paper. -R: catalytic reactions of water with e.g., galvanized steel. -these low-temperature faults, including corona PDs, are of little concern in transformer. 11

12 Additional Sub-Types of Faults Detectable by DGA -T3/T2 in oil only: at T >700/ 300ºC, of minor concern as long as they do not evolve into faults D1, D2 or C. -C: carbonization of paper at T >300ºC, potentially more dangerous (loss of insulating properties of paper). 12

13 DGA Diagnosis Methods -Key Gas, Rogers and IEC methods. Limitations are high % of wrong diagnosis (50%) or undiagnosed cases (30%), respectively. -Duval Triangle 1, allowing to detect the 6 basic types of faults (PD, D1, D2, T3, T2, T1 + DT). -Duval Triangles 4 and 5, allowing to detect the 5 sub-types of faults (S, O, R, T3/T2 in oil, C), and to distinguish between faults of lesser concern in oil and more serious faults in paper. 13

14 Duval Triangles 1, 4 and 5 Triangle 1 Triangle 4 Triangle 5 14

15 Use of Triangles 4 and 5 -Triangles 4 and 5 should never be used in case of faults identified with Triangle 1 as faults D1 or D2. -Triangle 4 should be used only for faults identified first with Triangle 1 as low temperature faults PD, T1 or T2, or when there is a high level of H 2. -Triangle 5 should be used only for faults identified first as high temperature thermal faults T2 or T

16 Mixtures of Faults -mixtures of faults sometimes occur rather than «pure» faults and may be more difficult to identify with certainty. -for instance, mixtures of faults D1 and T3 may appear as faults D2 in terms of gas formation. 16

17 New Faults vs. Old Faults: -when a new fault appears, as evidenced by a change in gas pattern, a more precise identification of the new fault may be obtained by subtracting the gas concentrations corresponding to the old fault from those corresponding to the new one (incremented values). -this, however, introduces additional uncertainty on the subtracted value. 17

18 Interpretation of CO and CO 2 -Until recently, CO and CO 2 were considered as good indicators of paper involvement in faults. Recent investigations at CIGRE, however, have shown that this is not always the case. -High concentrations of CO (>1000 ppm) and/or low CO 2 /CO ratios (<3), WITHOUT the formation of significant amounts of hydrocarbon gases, are NOT an indication of a fault in paper, particularly in closed transformer, but are rather due to oil oxidation under conditions of limited supply of O 2. 18

19 CO 2 and CO from Closed Transformers 56 MVA, 220kV Manufactured 2006 Rubber Bag Ref: I.Hoehlein, CIGRE TF15 (2010) 19 19

20 Interpretation of CO and CO 2 -High concentrations of CO (>1000 ppm) and low CO 2 /CO ratios (<3), TOGETHER WITH the formation of significant amounts of hydrocarbon gases, may be an indication of a fault in paper (to be confirmed with Triangles 4 or 5 and furans). -High concentrations of CO 2 (>10,000 ppm), high CO 2 /CO ratios (>20) and high values of furans (>5 ppm) are an indication of the slow degradation of paper at relatively low temperatures (<140 C), down to low degrees of polymerization (DP) of paper. 20

21 Interpretation of CO and CO 2 -Low concentrations of CO and CO 2, below condition 1 of IEC or IEEE (750 and 7500 ppm, respectively), correspond to normal gassing in transformers without faults. -Intermediate concentrations of CO, CO 2 and CO 2 /CO ratios may indicate a slow degradation of paper and intermediate DPs of paper, of no concern at all for the normal operation of the transformer. 21

22 Interpretation of CO and CO 2 -Zero or very low rates of change of CO and CO 2 do not necessarily mean the absence of a fault in paper. Localized faults in paper often do not produce detectable amounts of CO and CO 2 against the usually high background of these gases in service. -However, they do produce significant amounts of the other hydrocarbon gases, allowing the detection of faults in paper with Triangles 4 or 5. 22

23 Example of a Localized Fault in Paper 23

24 CIGRE Risk of Failure vs. CO 2 -The risk of failure is very low at high CO 2 values, which are strongly correlated with paper degradation and low DPs of paper, suggesting that the risk of failure at low DPs of paper is also very low, not very high as generally mentioned. -Indeed, large numbers of transformers have been observed at CIGRE to operate quite normally with DPs of paper < And no cases have been reported so far of transformers with DPs < 200 that failed because of the mechanical weakness of paper, even when subjected to external short-circuits

25 Transformers at Risk of Failure -So, in a large majority of cases, low DPs of paper do not mean the «end-of-life» of transformers as generally assumed. -The main concern with low DPs of paper is the shrinkage of paper and loosening of windings, not the mechanical (tensile) strength of paper. This can be mitigated by reclamping transformers. -Transformers most at risk of failure are gassing transformers that cannot be fixed

26 Factors Influencing the Interpretation of DGA Results -Type of fault (electrical, thermal) -Location of fault (paper, oil) -Gas concentrations, gassing rates (conditions 1 to 4) 26

27 Typical / Condition 1 Values -Typical /condition 1 values of IEC/ IEEE correspond to a given percentile (90%) of the population of DGA results -They mean that 90% of DGA results for dissolved gases are below these 90% Typical values -They are used to concentrate maintenance efforts on the 10% of the population with the highest gas levels and therefore most at risk 27

28 Typical / Condition 1 Values -Below typical/ condition 1 values, gas formation is considered not to be a concern for the equipment. -Below these values, it is recommended to use normal sampling frequency (monthly, semi-annual, etc.,..) and not to attempt a diagnosis. -Above these values, it is recommended to use increased sampling frequency (e.g., monthly or weekly) and a DGA diagnosis may be attempted. 28

29 90% Typical (Condition 1) Values for Concentrations at IEC (2007), in ppm (vs. source) 29

30 90% Typical (Condition 1) Values for Concentrations at IEEE (2013), in ppm (vs. kv, MVA, age, %O 2 ) 30

31 90% Typical (condition 1) Values for Gassing Rates, in ppm/month 31 31

32 Pre-failure (Condition 4) Values -CIGRE has evaluated the probability of having a failurerelated event (PFS) in service vs. gas concentration and gassing rate. -Based on these PFS curves, pre-failure (condition 4) values have thus been established, as well as intermediate conditions 2 and 3. 32

33 Risk of Failure vs. Gases Formed (PFS = Probability of Failure in Service)

34 CIGRE/IEC Sampling Intervals vs. Concentrations in Service, in ppm 34 34

35 CIGRE/ IEC Sampling intervals vs. Gassing Rates in Service, in ppm/month 35 35

36 Actions Recommended by IEC at Conditions 1-4 -Condition 1: increase oil sampling frequency for DGA -Conditions 2-3: consider complementary tests (infrared scans, acoustic tests, PD tests, effect of load). -Conditions 3-4: consider transformer inspection. -Condition 4: consider transformer repair or replacement. 36

37 Transformer Parameters Influencing Conditions 1-4 -CIGRE (2006)/ IEEE (2013): -Operating conditions (load, climate) -Age (new, old) -Type (power, core, shell, instrument, reactor). -MVA, voltage -Open or closed -CIGRE WG47 (2013): -Fault type 37

38 Occurrence of Faults in Service at CIGRE 38 38

39 Effect of Type of Thermal Fault on Condition 1 Values at CIGRE (ppm) (ppm) 39 39

40 Effect of Type of Electrical Fault on Condition 1 Values at CIGRE: (after deleting C 2 H 2 < 2 ppm) (ppm) (ppm) 40 40

41 Effect of Type of Fault on Condition 4 values at CIGRE: (in ppm, using previous adjustment factors) 41 41

42 Comparison with Cases of High Gas Levels without Failure at CIGRE: (in ppm) 42 42

43 Monitoring with DGA -Monitoring off-line (by manual or laboratory DGA) is mostly used but cannot detect faults occurring between two oil samplings (e.g., every year, month or week). -On-line multi-gas or hydrogen monitors can detect abnormal and/or quick-developing faults occurring within days or hours between oil samplings. 43

44 Abnormal and Quick-Developing Faults -Abnormal gassing (above condition 1 for concentrations and gassing rates) will occur in 200 of the 2000 transformers. -Quick-developing faults (above condition 4 for gassing rates) will typically occur in 20 to 40 of them. 44

45 Detection of Quick-Developing Faults with a Multi- Gas Monitor in a 3-Phase GSU Transformer Day 2 16:00 Day 3 12:00 Day 2 12:00 Day 3 04:00 Day 3 00:00 Day 2 20:00 Day 3 16:00 Day 3 08:00 Day 23 04:00 to Day 24 08:00 Followed by transformer failure C 2 H 2 = 800 ppm/day! 45

46 700 MVA Transformer C 2 H 2 = 45 ppm/day! 46 46

47 336 MVA Transformer (Placed in Service -1969) C 2 H 4 = 300 ppm/day! 47

48 1100 MVA Transformer C 2 H 4 = 300 ppm/day! 48

49 -Gassing rates were all significantly above condition 4 values in the previous 4 examples. -The corresponding transformers were removed from service 1 to 3 days after looking at monitor readings, before potential catastrophic failure. -However, it might have been better to remove them from service earlier. -Without an on-line monitor, these transformers would possibly have suffered catastrophic failures. 49

50 On-Line Monitoring with Multi-Gas Monitors - Multi-gas monitors will detect all types of faults, even in their early stages at condition 1, and without false alarms. However, they are more expensive than hydrogen only monitors. - The recommendation of CIGRE (TB # 409, 2010) is therefore to use multi-gas monitors in critical transformers (GSU, nuclear, transmission) and in abnormally gassing transformers. 50

51 Fault Detection with Hydrogen Monitors Note: for faults T3 in paper (C), curve for H 2 is a bit higher. Ref: Duval, TSUG

52 Fault Detection with Hydrogen Monitors -Hydrogen monitors are most sensitive to stray gassing of oil S (occurring in ~ 25% of cases), and to corona partial discharges PD (occurring in only 0.3% of cases). -Such faults will commonly produce thousands of ppm of H 2 without being a concern for the transformers. If the limit in hydrogen monitors is set at average condition 1 values for H 2 (100 ppm or 7 ppm/month), this may result into many false alarms. 52

53 Fault Detection with Hydrogen Monitors -Faults D1/D2 at dangerous condition 4 of CIGRE will produce 0.5 ppm/day of C 2 H 2 together with only 1 or 2 ppm/day of H 2. -If the limit for H 2 in the monitor is set at average condition 1 (100 ppm), the monitor will detect these faults only in their late stages (condition 3 or 4), when dangerous levels of 25 to 50 ppm of C 2 H 2 have already formed. -If it is set at 5 ppm over a period of 3 days, this may result into many false alarms. 53

54 Fault Detection with Hydrogen Monitors - In case of thermal faults T3/T2/T1/O the main gas formed is C 2 H 4, CH 4 or C 2 H 6, together with 3 to 10 times less of H 2. If the limit for H 2 is set at 100 ppm, the monitor will detect these faults only in their late stages (condition 3 or 4). - Decreasing the limit for H 2 in the monitor (e.g., to 50 or 20 ppm) will increase the number of false alarms due to faults S or corona PD of lesser concern. - The recommendation of CIGRE (in TB # 409, 2010) is therefore to use hydrogen monitors in non-critical transmission and distribution transformers, and in transformers with no previous gassing history. 54

55 Examples of On-Line Gas Monitors 55

56 Multi-Gas Monitors Monitors of the chromatographic type: -after gas extraction, will separate individual gases on a GC column, then measure them with GC detectors. -TM8, TM3 (Serveron) -Calisto 9 (Morgan Schaffer) 56

57 Monitors of the Chromatographic-Type: -use the same standardized, NIST-traceable technique as laboratories. -provide automatic recalibration at fixed intervals as laboratories do. -require some maintenance (change of carrier gas, calibration gas mixture, GC columns every 3 to 5 years). 57

58 Monitors of the Infrared-Type: -after gas extraction, will measure directly individual gases with an infrared detector, and H 2 with a solid state sensor -Transfix 8, Transport-X 7 (GE-Kelman) use a photo-acoustic (PAS) detector. -LumaSense 9 uses a non-dispersive IR detector. 58

59 Monitors of the infrared type: -do not require change of carrier gas and gas mixture. -cannot measure H 2, O 2 by infrared, requiring the use of relatively inaccurate solid state sensors for that purpose. -some may need recalibration because of contaminations in the ambient air (SF 6, oil vapours, solvents) and lamp fade with time; some cannot be recalibrated in the field. -require change of infrared lamp ~ every 5 years. -contain several moving parts. 59

60 Hydrogen Monitors -Hydran (GE): measures 100% of the H % of the CO present in oil with a PTFE membrane and fuel cell detector. -Calisto 2 (Morgan Shaffer): measures H 2 only with a PTFE membrane, GC and TCD detector. -TM1, Qualitrol, Weidmann: measure H 2 with an inorganic membrane and an H 2 Scan Pd solid state sensor. -TM1 (Serveron): improved version of H 2 Scan. 60

61 Other Applications of DGA -DGA can also be used to detect faults in LTCs, using for example Duval Triangle 2 for compartment types, and Triangles 2a to 2e for in-tank types. -it can also be used for oils other than mineral oils, such as natural esters (FR3, BioTemp), synthetic esters (Midel) and silicone oils, using for example Duval Triangles

62 DGA in LTCs at IEC/ IEEE: 62 Duval Triangle 2 for compartment types Duval Triangles 2 for in-tank types N1 (MR types M, D) N3 (MR types VR, VV) N4 (MR types R, V) N5 (MR types G, UZD) 62

63 Duval Triangles 3 for Non-Mineral oils Mineral oil 63 FR3 63

64 DGA in wind farm transformers at CIGRE -Because they are usually Padmount transformers not designed for that purpose, many tend to form lots of gases, as a result of: -Corona PDs, because of poor oil impregnation. -Stray gassing of oil, because of abnormal overheating

65 Stray gassing of oil at CIGRE -With mineral oil, H 2 at T<120C and CH 4, C 2 H 6 at T>200C. -With vegetable oils (e.g.,fr3), H 2 at T<70C and C 2 H 6 at higher temperatures (Triangles 6 and 7). -With silicone oils, H 2 at T>200C