GE Energy Management 18th Conference On Line Monitoring and Diagnostics

For Power Delivery Equipment

Bethesda, Maryland November 13-15, 2000

The Move Toward Dynamic Loading of

Power Transformers

by David J. Woodcock

Vice President Marketing Weidmann Systems International Inc.

The Move Toward Dynamic Loading of Power Transformers

By David J. Woodcock Weidmann Systems International Inc

.

I. INTRODUCTION: Transformer Loading Policy and Effect on Operation The new deregulated electric utility environment is driving Transmission and Distribution companies to find ways to improve their competitive position. Maximizing return on investment (ROI) is often a key financial driver when formulating a profitable T & D operation and maintenance strategy. This strategy requires that utility operations and maintenance find ways to leverage the most out of existing transformers.

Increased equipment utilization, deferred capital expenditure and reduced maintenance expense are all a part of the guidelines for today’s T & D asset strategists and managers. Although tighter operating budgets and reduced spending are nothing new to utility engineers and planners, today’s increased need to leverage more out of existing equipment must be achieved with the majority of T&D assets nearing the end of their life cycle.

At many Transmission and Distribution companies, the majority of substation assets are 20 to 40 years old. Power Transformer capacity additions have reduced from 185 GVA (giga Volt Amperes) to 50 GVA per year over the past twenty-five years (Figure 1).(1)

Most annual transformer additions are primarily required to replace failed units while approximately 40 per cent of additions are for load growth. However, the net effect of the twenty-five years of declining capital spending has been a significant accumulated increase in utilization, or transformer load factor, over this period. Within this framework, scheduled maintenance is being replaced by condition-based maintenance where equipment monitoring and diagnostics play an increasingly important role. In addition, real time monitoring of equipment and it’s operating environment will enable load planners to dynamically load transformers to optimum limits without compromising reliability. This paper discusses today’s loading practices and the limitations in setting future dynamic loading criteria. A case study is provided to demonstrate the development of a thermal model which covers ambient temperature cycle, load profiles and operating modes as the key dynamic parameters.

II. Today’s Loading Practices - An Industry Survey A 1998 survey was conducted with a representative sample of U.S. utility companies to try to understand, in a general way, what loading practices are followed today. The survey discussed both specific limits used and in general what factors are evaluated when determining a loading policy. A summary of the results shown in Table I indicate that almost 30% of utility customers are moving toward dynamic loading at this time.

TABLE I Survey Results (Yes/No)

Questions

Yes No

1. Do you use values in C57.91 to determine loading? 82% 18% 2. Do you adjust loading limits based on changes in load profile?

68% 32%

3. Do you adjust loading limits based on changes in ambient temperature?

78% 22%

4. Do you have a computer based planning program for loading beyond nameplate?

63% 37%

5. Do you consider bubble formation in your loading criteria?

25% 75%

6. Do you consider age and vintage of the transformer? 28% 72% 7. Do you adjust loading based on equipment condition appraisal or ranking system?

24% 76%

8. Do you adjust loading based on the use of on-line monitoring?

3% 97%

9. Do you have the same loading limits for distribution, transmission, and generation units?

45% 55%

10. Are you considering changing from a static to a dynamic transformer loading practice?

28% 72%

III. Dynamic Loading Modes of Operation For many years the limit for normal transformer loading was based on the maximum nameplate rating. However, transmission and distribution substation transformers have historically been loaded beyond nameplate rating to accommodate emergency or contingency conditions. Until recently, the operation of transformers would fit into one of the following loading categories.(3,4)

1. Normal life expectancy loading - Continuous Load

As the term implies, this is the constant loading at rated nameplate output (MVA) when

the transformer is operated under a constant 30°C ambient condition. This condition implies a continuous hot spot conductor temperature of 110° C, which is the sum of the following temperatures: 65°C (ave. winding rise) + 30°C (ambient) + 15°C (hot spot

rise) = 110°C. Of course, this loading condition rarely happens over the life of a transformer, where both load and ambient temperature vary over time.

2. Normal Life Expectancy Loading - Cyclical Load

This loading implies a cyclical load at a normal constant ambient (30°C) where the

hottest spot conductor temperature varies above and below the normal 110° C, as the load cycles above and below the nameplate MVA of the transformer. From the thermal aging standpoint, this cycle is equivalent to the case of rated constant load at normal ambient temperature (30°C). This is the case because, thermal aging is a cumulative effect over time and temperatures above 110° C are permitted provided the transformer is operated for much longer periods below 110°C. Of course, maximum allowable hot spot and top oil temperatures can not be exceeded.

3. Long Time Emergency Loading

This operation results from the prolonged outage of a system component which causes

transformer loading that results in hottest spot conductor temperatures in the range of 120 - 140°C. This type of occurrence would be rare and would be expected to happen two to three times over the transformer life and each event may last weeks to months. This type of operation causes accelerated aging of the transformer insulation system, and may have other associated risks. Loss of insulation life calculations should be made to assure it is acceptable for such an event and top oil temperatures should not exceed 110°C.

4. Short-time Emergency Loading

This loading condition is unusually quite high, and is caused by one or more events

which seriously disturb normal system loading and are expected to occur rarely, two to three times over the transformer life. This loading condition can cause hottest-spot conductor temperatures as high as 180°C for a short period of time. Significant acceleration in insulation loss of life can occur during this event, and calculations should be made to determine if the loss is acceptable. Because of the rapid aging, load must be reduced fast, typically within two to four hours. This type of loading has several risks associated with it, such as, reduced dielectric strength, stray flux heating and exceeding ancillary equipment ratings.

The move toward dynamic loading will include all of the above operating modes in addition to a relatively new loading condition which came into existence in 1995. This new mode of operation is driven by the need to utilize assets more effectively, without compromising the overall life expectancy of the transformer. This new loading condition is:

5. Planned Loading Beyond Nameplate - Normal Operation(3)

This loading results in the conductor hottest-spot or top-oil temperature

exceeding the limits suggested for normal life expectancy loading. This loading is accepted by the user as a normal, planned-for operating condition. There is no associated equipment outage or emergencies with this type of loading. Cyclic loads resulting in hottest-spot conductor temperatures in the range of 120° - 130°C would be associated with this loading requirement. This type of loading would occur frequently, and in some cases daily, during a short part of the transformer’s load cycle. Loss of insulation life calculations must be done to make sure it is acceptable for this loading condition.

TABLE II shows the suggested maximum temperatures given in ANSI/IEEE C57.91-1995 and IEC Standard 354 for the four types of transformer loading. In addition to this criteria, it is always advisable to calculate the loss of insulation life and make sure it is acceptable for the loads beyond nameplate. Acceptable limits of loss of insulation life for various loadings is very important in developing a loading policy and thermal model limits to facilitate real time dynamic loading.

TABLE II Suggested Maximum Temperature Limits - °C

IEC vs. IEEE

Normal Life

Expectancy

Planned Loading

Beyond NP

Long-Time Emergency 1-3 Months

Short-Time Emergency 1/2-2 Hours

IEEE

120°C

130°C

140°C

180°C

Insulated Conductor Hottest Temperature IEC 120°C (N/A) 130°C 160°C

IEEE

140°C

150°C

160°C

200°C

Other Metalic (Supports, core, etc.) IEC (N/A) (N/A) (N/A) (N/A)

IEEE

105°C

110°C

110°C

110°C

Top Oil Temperature

IEC 105°C (N/A) 115°C 115°C IEEE

(N/A)

(N/A)

(N/A)

1.5 pu

Load Factor Per Unit Current IEC 1.3 pu (N/A) 1.3 pu 1.5 pu

IV. Additional Limitations Set by Temperature The top-oil temperature is limited to 105°- 110°C in IEEE/ANSI because of the ancillary equipment located in the top oil of the transformers. Bushings which do not utilize thermally uprated insulating paper are components which typically set this upper limit. Transformer loading studies should include, in addition to winding, hottest spot and top oil temperatures, calculation for the temperature rise of the other current carrying components such as: bushings,

tap changers, cables, etc. For example, both the steady state and transient hottest spot temperature can be calculated for bottom connected bushings, using the method described in ANSI/IEEE C57.19.100, “Guide for Application of Power Apparatus Bushings”. The steady state (S.S.) temperature rise can be calculated using Equation #1.

∆θ HS = K1In + K2∆θo (Equation #1)

Where: ∆θ HS = S.S. Hottest Spot Rise Over Ambient (°C)

∆θo = S.S. Immersion Oil Rise Over Ambient (°C)

I = Per Unit Load Current Based on Bushing

n, K1, K2 = Constants Specific to Bushing

The transient hottest spot temperature of the bushing can also be calculated using a transient approach which includes calculation of top oil temperatures. A more conservative single step method can also be used to calculate the final hottest spot temperature, and is outlined in the above reference guide. The contact temperature for tap changes and temperature rise of lead cables should also be calculated to make sure they do not limit the load capacity of the transformer. Relay settings must be checked so load is not dropped unintentionally and oil expansion space may also become critical at higher loads. Additional care must be used when evaluating large power transformers loaded beyond nameplate due to stray flux heating. The sensitivity of transformers being loaded beyond nameplate rating is very dependent on size. As size increases, leakage flux density and short circuit forces will also increase. The increased leakage flux of larger units at loads beyond nameplate may cause additional eddy-current heating of metallic structural components in the transformer. It can also be more difficult to accurately determine the hot spot temperature on larger units. Because of these considerations, and the magnitude of the consequences of failure, larger transformers (>100 MVA) require a more individual approach to loading criteria beyond nameplate than smaller units. It is also recommended that dissolved gas analysis tests be conducted after any significant loading beyond nameplate along with other diagnostic tests to evaluate the result of such loading. The use of planned loading of transformers beyond their nameplate rating, not only for emergency conditions but for normal operation, has initiated an IEEE/ANSI Standard, (C57.119) specifically designed to enable factory testing of units for this capability. During this test, the

transformer’s thermal characteristics are evaluated at loads beyond nameplate. These thermal characteristics can then be applied to the transformer thermal model for better prediction of performance at loads beyond nameplate. V. New Loading Practices and Effect on Operation We have discussed the gradual increase in T & D transformer load and the industry business need to further ratchet-up normal and contingent loading limits. This is reflected in the added flexibility provided to load planners in the 1995 revision of ANSI/IEEE C57.91. The inclusion of the Planned Loading Beyond Nameplate condition permits higher temperature for periodic or daily cyclical limits. However, the revised limits require the user to be more rigorous in calculating the loss of insulation life for various loading criteria. A typical transformer loading policy may include suggested loading criteria and limits as shown in Table III.

TABLE III Typical Loading Criteria and Limits

Normal Life

Expectancy Planned

Loading Beyond Nameplate

Long Term Contingent

12 hour Contingent

2 hour Contingent

Insulated Conductor Hot Temperature

120°C

130°C

140°C

160°C

180°C

Other Metalic Hot Spot Temperature Limits

140°C

150°C

160°C

180°C

200°C

Top Oil Temperature

105°C

110°C

110°C

110°C

110°C

Per Unit Load Current

1.3pu – 1.5pu

1.3pu – 1.5pu

1.3 to 1.5pu

1.5

1.5

Loss Of Insulation Life Per Cycle

*.037%

*.037%

0.5 to 1.0%

1.0 to 2.0%

2.0 to 4.0%

*Based on 65,000 hour design life at constant load and ambient limits for 50% insulation tensile (not 200 DP). To establish the loading limits for any given transformer thermal model, it is necessary to calculate the above criteria or which ever limit occurs first, for the expected seasonally adjusted loading cycle and ambient temperature. The temperature calculations (in degrees C) should also include:

a) Top oil b) Top duct oil

c) Bottom oil d) Winding hot spot e) Average oil rise f) Average winding rise g) Winding hot spot gradient h) Average winding gradient i) Bushing gradient j) Cable gradient k) Tap changer contact gradient

It is necessary to have specific design data or to make assumptions based on normal design practice in order to calculate some of the above parameters. In addition to the above temperature limits, when considering upper loading limits, it is important that the other following calculations be performed for some or all cases:

a) Loss of life in % b) Bubble evolution probability c) Regulation and voltage drop in % d) Loading capability in peak output MVA and per unit accounting for voltage

regulation. e) Current in amps accounting for voltage regulation f) Regulated and unregulated output voltage

VI. Developing a Thermal Model to Optimize Load Capability

In future load planning scenarios, these thermal model characteristics for each transformer would be programmed into a database and be available real time against which actual performance would be monitored. Transformer performance characteristics, in addition to information on both ambient temperature and loading cycle are critical in determining the transformer load available for normal operation and emergency events. In dynamic loading, these inputs are evaluated in real-time to allow the operator flexibility in deciding how much the unit can be loaded at any given point in time. This mathematical thermal model is then used to predict the individual transformer’s internal temperatures and insulation loss of life. A computer program is utilized to calculate temperatures of the winding, hottest-spot and top oil with various loading and ambient scenarios. These what-if cases allow the user to determine what the effects of load condition have on the life and health of the transformer. To effectively run the different cases of load and ambient on the thermal model, one must first establish loading criteria which is acceptable for the transformer. This loading criteria is typically established for normal loading, planned loading above nameplate, long-time emergency and short-time emergency cases as shown in Table III. Each of these operating modes has an increasing level of risk associated with it. This risk is balanced with the need to meet certain load condition periodically throughout the life of the transformer. In addition to the loading needs and associated risk, maximum loading criteria should reflect the overall condition of the transformer and its ability to withstand this additional stresses. A benchmarking or condition assessment of the companies transformer assets can help in establishment of an end-point of life

criteria (number of hours) the information can be used in the new per unitized life equation to predict percentage of loss of life.

VII. Thermal Model Development – Case Study

Description of Case Study The purpose of Case Study Thermal Model is to determine the dynamic loading capability which can practically be achieved for this transformer when considering a broad range of ambient temperatures, load profiles and operating modes. Methods The dynamic loading capabilities, temperature, and loss of life were determined based on the specified load and ambient cycles. Calculations were done according to the ANSI/IEEE Loading Guide for Transformers C57.91-1995. Transformer Type: 3 Phase, Load Tap Changing, Autotransformer MVA & Cooling: 120/160/200//224, 55/65°C Rise, OA/FA/FA Volts & Connection: 230000 GrdY – 67231 GrdY HV Taps: +/-5% in 4 – 2.5% Steps, FC LV Load Taps: +/-10 in 32 – 0.625% Steps, FC

Thermal Characteristics at 65°C Rise

Existing Hot spot rise (HSR) 73.8* Top Oil rise (TOR) 58.2 Average Winding Rise (AWR) 61.2 Hot spot over Top Oil (HS Grad) 15.6* Average Oil Rise (AOR) 48.2* Average Winding over Average Oil (Wdg Grad) 13.0* Top Oil over Average Oil (1/2 Delta T) 10.0* *Calculated values from test results. A. Limiting Criteria for Loading The following temperature limits were used in this study and loss of insulation life during normal and contingency operation (TABLE IV). These limiting criteria were agreed to limits set by the utility for the operation of this type of substation transformer. These limits may vary between utilities.

TABLE IV Load Limiting Criteria

Parameter

Normal Life Load

Long-Time Contingency

Short-Time Contingency

Max Hot Spot Temp. 120°C 140°C 160°C

Max Top Oil Temp 105°C 110°C 110°C

Max Loss Of Life/Cycle 0.037% 1.0% 1.0%

Bubbling in Oil No No Yes

VIII. System Peak Ambient Temperature

The peak ambient temperature cycles for summer and winter anticipated for are shown on Figure 2. The temperature differential at the peak of the daily cycle between seasons is 22°C, which is typical for this Southern USA location. When comparing real time data to the model, it is possible to locate the actual temperature and time against the typical profile and adjust the curve to provide the expected daily ambient cycle.

FIGURE 2 Summer & Winter Ambient Cycle

IX. Load Cycles The load cycles given in Figure 3 represent the system average for summer and winter. In ideal circumstances the actual historical or future load profile for the specific substation bank would be preferable and provide a more accurate model. The load cycles given are for typical summer cooling (air conditioning) and winter electric heating loads, hence the difference in peak timing at 16.00 and 08.00 respectively. In dynamic load forecasting of future load capability, based on real time monitoring, it is essential that season and time be known when actual data is compared to the thermal model in order to find location in the appropriate ambient temp or load cycle curve. In the case example given in Figure 3 the same loading point (p.u.) can be found five (5) times at the end and in mid cycle, and the load can be rising or falling depending on time and season.

FIGURE 3 Load Cycles - Winter & Summer

X. Computing Results The computed results for summer and winter ambients and loading cycles, for normal and contingent loading cases is given in Table V through VIII, with the associated temperature and p.u. load profiles given in Figures 4 through 11. The thermal model load limits are based on iteration to find the hot spot temp, top oil temp or accumulated loss of insulation life, which ever occurs first. It can be seen from the data given in Table IX, that peak loading for this unit occurs at 1.125 to 1.405 p.u. for normal summer vs. winter and from 1.215 to 1.560 p.u. for the contingency modes. It is important to note that normal load are limited by hot spot temperature and contingent loads are limited by top oil temperature. This is typical, but depends entirely on the specific

transformer design, cooling configuration and load cycle profile. The incremental capability between normal and short-term contingency load is highly dependent on the time and rate of rise, which is superimposed onto the normal operating cycle. The case study assumes that the contingency occurs at the peak cycle (worst case scenario) with the unit operating at 80% of its normal load cycle peak limit. Accumulated loss of insulation life can also be calculated based on actual load criteria and computed to determine residual insulation life.

Table V 24-Hour Normal, Base Load Summer

Time P.U. Load

Ambient Temp.

Hot Spot Temp.

Top Oil Temp.

Top Duct Oil Temp.

Bottom Oil Temp.

kVA Load

0 0.710 26.8 76.9 68.4 64.9 52.1 159,012 1 0.665 25.8 73.6 64.6 62.0 48.9 148,990 2 3 4

0.621 0.593 0.570

25.4 25.1 24.7

69.1 65.2 62.0

60.9 57.7 54.9

58.3 55.1 52.4

46.1 43.6 41.5

139,201 132,786 127,743

5 0.560 24.5 59.5 52.6 50.4 39.8 125,407 6 0.572 24.2 58.1 51.1 49.3 38.6 128,151 7 8

0.615 0.661

24.4 25.4

58.2 59.7

50.5 51.3

49.6 51.2

38.3 39.1

137,866 148,063

9 0.727 27.7 64.0 53.5 54.5 41.3 162,784 10 11

0.801 0.897

29.7 31.2

70.4 78.9

57.6 63.5

59.5 66.0

44.8 49.5

179,470 200,866

12 0.983 32.3 88.5 70.7 73.7 55.2 220,222 13 1.054 32.9 98.0 78.6 81.5 61.3 236,204 14 15

1.110 1.119

33.6 34.2

107.0 113.2

86.4 92.9

89.1 95.0

67.5 72.8

248,663 250,628

16 1.125 34.4 117.4 97.6 99.1 76.6 252,000 17 18 19

1.115 1.100 1.063

34.2 33.5 32.5

119.5 119.8 118.1

100.5 101.7 101.0

101.4 102.0 100.7

78.9 79.7 79.0

249,664 246,364 238,206

20 1.011 30.9 114.4 98.4 97.2 76.5 226,563 21 22

0.966 0.912

29.3 28.3

109.3 103.3

94.3 89.4

92.6 87.3

72.9 68.8

216,403 204,351

23 0.813 27.4 95.5 83.5 80.5 63.9 182,029 24 0.710 26.8 86.5 76.5 72.8 58.3 159,012

Top Oil Temperature = HotSpot Temperature =

Loss of Life =

Maximum kVA Load = Maximum P.U. Load =

Limit 105.0 120.0 0.0371

252,000 1.125

Actual 101.7 119.9

0.0237

Table VI 4-Hour Contingency, Base Load Summer

Time P.U. Load

Ambient Temp.

Hot Spot Temp.

Top Oil Temp.

Top Duct Oil Temp.

Bottom Oil Temp.

kVA Load

0 0.631 26.8 76.9 68.4 64.9 52.1 141,344 1 0.591 25.8 70.7 63.0 59.5 47.7 132,436 2 3 4

0.552 0.527 0.507

25.4 25.1 24.7

65.3 61.1 57.7

58.4 54.7 51.7

55.1 51.7 48.9

44.2 41.4 39.2

123,734 118,032 113,549

5 0.498 24.5 55.2 49.4 46.9 37.5 111,473 6 0.509 24.2 53.7 47.8 45.8 36.3 113,912 7 8

0.547 0.588

24.4 25.4

53.5 54.6

47.1 47.5

45.9 47.1

35.9 36.5

122,547 131,612

9 0.646 27.7 57.8 49.2 49.9 38.4 144,697 10 11

0.712 0.797

29.7 31.2

63.2 70.4

52.6 57.5

54.2 59.7

41.3 45.2

159,529 178,547

12 0.874 32.3 78.4 63.5 66.0 49.9 195,753 13 0.937 32.9 86.3 70.0 72.5 54.8 209,959 14 15

1.199 1.208

33.6 34.2

104.9 117.0

80.2 92.9

85.4 96.7

62.8 72.8

268,556 270,678

16 1.215 34.4 124.6 101.5 104.2 79.8 272,160 17 18 19

1.204 1.188 0.945

34.2 33.5 32.5

128.8 130.4 120.5

107.0 109.6 105.7

108.6 110.5 102.9

84.1 86.1 82.7

269,637 266,073 211,739

20 0.899 30.9 110.8 97.2 94.2 75.5 201,389 21 22

0.859 0.811

29.3 28.3

102.6 95.0

89.7 83.2

86.9 80.3

69.3 63.9

192,358 181,646

23 0.722 27.4 87.0 76.8 73.4 58.6 161,803 24 0.631 26.8 78.6 70.1 66.2 53.4 141,344

Top Oil Temperature = HotSpot Temperature =

Loss of Life =

Maximum kVA Load = Maximum P.U. Load =

Limit 110.0 160.0 1.0000

272,160 1.215

Actual 109.7 130.4

0.0382

Figure 4 24-Hour Normal, Base Load Summer

Figure 5

Figure 6 4-Hour Contingency, Base Load Summer

Figure 7

Table VII 24-Hour Normal, Base Load Winter

Time P.U. Load

Ambient Temp.

Hot Spot Temp.

Top Oil Temp.

Top Duct Oil Temp.

Bottom Oil Temp.

kVA Load

0 1.142 4.1 57.9 45.5 44.4 29.2 255,867 1 2 3

1.122 1.131 1.165

0.1 -0.2 -0.6

75.9 80.3 84.8

54.4 59.4 63.2

56.3 60.5 64.3

35.3 39.1 42.1

251,224 253,371 261,001

4 1.191 -0.9 88.9 66.7 67.7 44.9 266,714 5 6 7

1.226 1.266 1.331

-1.2 -1.3 -1.7

93.2 98.1

104.8

70.1 73.8 78.5

71.2 75.1 80.2

47.5 50.5 54.2

274,690 285,509 298,156

8 1.405 -1.2 113.6 84.8 87.2 59.5 314,720 9

10 1.399 1.330

1.0 3.4

119.3 119.5

91.0 94.1

93.0 94.9

65.1 68.0

313,301 297,926

11 1.244 5.7 115.5 93.3 93.0 67.7 278,639 12 1.101 7.7 107.5 88.6 86.7 64.2 246,623 13 14

1.007 0.939

9.3 10.3

98.2 89.9

81.6 74.8

79.1 72.2

58.8 53.5

225,611 210,388

15 0.870 11.1 82.2 68.6 66.0 48.8 194,936 16 17 18

0.858 0.891 0.980

11.4 10.8 9.2

76.9 74.7 76.3

63.7 60.9 60.6

61.6 59.6 60.5

44.9 42.6 42.1

192,099 199,537 219,591

19 1.125 7.4 84.3 63.9 65.3 44.2 252,029 20 1.166 6.4 90.7 69.0 70.4 48.1 261,231 21 22

1.191 1.186

5.3 4.9

95.2 97.4

73.2 75.9

74.3 76.6

51.2 53.4

266,714 265,718

23 1.174 4.2 97.9 77.1 77.2 54.2 262,880 24 1.142 4.1 96.6 76.7 76.4 53.9 255,867

Top Oil Temperature = HotSpot Temperature =

Loss of Life =

Maximum kVA Load = Maximum P.U. Load =

Limit 105.0 120.0 0.0371

314,720 1.405

Actual 94.2 120.0

0.0182

Table VIII 4-Hour Contingency, Base Load Winter

Time P.U. Load

Ambient Temp.

Hot Spot Temp.

Top Oil Temp.

Top Duct Oil Temp.

Bottom Oil Temp.

kVA Load

0 0.813 4.1 57.9 45.5 44.4 29.2 182,112 1 2 3

0.798 0.805 0.829

0.1 -0.2 -0.6

56.4 54.5 53.9

44.2 42.1 41.1

42.3 40.5 39.9

27.3 25.6 24.7

178,807 180,335 185,766

4 0.847 -0.9 54.0 40.8 40.0 24.5 189,832 5 6 7

0.873 1.405 1.478

-1.2 -1.3 -1.7

55.0 82.9

105.1

41.2 50.9 70.9

40.6 57.2 76.4

24.7 32.2 48.1

195,509 314,785 331,048

8 1.560 -1.2 123.8 88.1 93.1 62.3 349,440 9

10 1.553 1.477

1.0 3.4

135.9 139.4

101.8 109.2

105.6 111.2

74.1 80.7

347,865 330,793

11 0.885 5.7 113.9 98.9 92.4 72.3 198,320 12 0.784 7.7 92.2 79.9 73.7 57.1 175,532 13 14

0.717 0.668

9.3 10.3

77.3 66.8

66.5 57.1

61.3 52.9

46.7 39.6

160,577 149,743

15 0.619 11.1 59.1 50.5 46.8 34.7 138,745 16 17 18

0.610 0.634 0.698

11.4 10.8 9.2

54.1 51.5 51.4

45.8 43.0 41.8

42.9 40.8 40.5

31.3 29.0 27.8

136,725 142,019 156,292

19 0.801 7.4 54.1 42.4 42.2 27.7 179,380 20 0.830 6.4 56.5 44.1 43.9 28.7 185,930 21 22

0.847 0.844

5.3 4.9

58.3 59.1

45.4 46.1

45.0 45.5

29.4 29.9

189,832 189,123

23 0.835 4.2 59.0 46.2 45.3 29.8 187,103 24 0.813 4.1 58.0 45.6 44.5 29.3 182,112

Top Oil Temperature = HotSpot Temperature =

Loss of Life =

Maximum kVA Load = Maximum P.U. Load =

Limit 110.0 160.0 1.0000

349,440 1.560

Actual 109.5 139.4

0.0498

Figure 8 24-Hour Normal, Base Load Winter

Figure 9

Figure 10 4-Hour Contingency, Base Load Winter

Figure 11

TABLE IX

Peak Loading Range

Operating Mode

Normal Summer

Normal Winter

Contingent Summer

Contingent Winter

Ambient Cycle

S W S W

Load Cycle

S W S W

Max. Peak Load MVA

252.0 314.7 272.1 349.4

Peak Time Hr.

16.00 08.00 17.00 08.00

P.U. Peak Rating

1.125 1.405 1.215 1.560

Hot Spot Temperature

119.8 120 130.2 139.4

Top Oil Temperature

101.6 94.2 109.6 109.5

Loss of Ins. Life Per Cycle

0.023 0.018 0.037 0.050

XI. On-Line Monitoring for Dynamic Loading On-line monitoring of Power Transformers, for condition assessment, has gained popularity over the past ten years; the typical technology adoption period, from concept to commercial reality, in the electric utility industry. The benefits of on-line monitoring have primarily accrued to reduction in maintenance cost and overall improvement in T&D system reliability. The prospect of using on-line monitoring to make intelligent decisions on how to optimize the load on such important substation assets as transformers follows the adoption of load management technology for power generation systems and equipment. The following selection list shows the basic difference in the typical instrumentation and monitoring devices required for dynamic loading compared to those required for condition assessment. Size of the unit and/or its system criticality, are often the key deciding factors on the selection of on-line monitoring expenditure. However, the tangible benefits related to Dynamic Loading are far greater and more easily identifiable than those attributed to reduced maintenance cost. In the final analysis, if the unit is not fit for the purpose or if its poor condition leads to sudden failure, the value of monitoring dynamic load capability becomes academic at the time. Clearly, condition assessment and dynamic load monitoring go together hand-in-glove.

On-line Monitoring Equipment Selection Lists:

Dynamic Loading Condition Assessment HV, LV Current (CT’s) Hydran HV, LV Volts (PT’s) Multi-Gas Analyzer Tap Position Indicator Bushing Pf Top Oil Temp Partial Discharge Bottom Oil Temp LTV Temp Delta Hot Spot Temp (Optional) LTV Vibration Ambient Temp Harmonic Spectrum Wind Velocity Moisture in Oil

Why monitor and dynamically load power transformers?

• To utilize transformer assets closer to their real operating limits without compromising their life expectancy or reliability.

• To determine when units are/are not performing in accordance with a pre-

determined dynamic thermal model.

• To fully optimize real-time substation loading based on changes in ambient condition or operating modes, i.e. Normal, L.T. or S.T. contingency.

• To assist in making intelligent decision about shifting load from the unit, based on

the time to reach peak load capability (as an early warning).

• To forecast operating conditions with given load shifted to the unit at a specific time or to determine how much load could be shifted to a unit.

• To intelligently shift load around a (network) T&D system in order to select

“good, better, best” options based on unit condition or load-loss characteristics, and to maximize financial benefits from reduction in cost of losses.

• To collect accumulated loss of insulation life data to enable forecasting of residual

life of transformers in the fleet. XII. Temperature Measurement Ambient, top and bottom oil temperature are basic requirements. From this minimum information, hot spot temperature can be calculated. If direct hot spot temperature probes are installed, then bottom oil temperature would not be required. However, even though hot spot temperature is vital to determining insulation loss-of-life, it is not always the dynamic load limiting factor. In many cases the top oil temperature limit will be reached prior to the unit reaching its hot spot limit. This depends on the specific design of the windings (lots of active material in low load-loss units) and the relative size of the tank and cooling system design

margin. This also depends on the mode of operation and the load cycle curve. A thermal model for each design and each operating mode is required to determine the appropriate limit. XIII. Load and Loss Measurement Phase current and voltage measurement from CT’s and PT’s for each phase and each side of the transformer (H.V. and L.V.) are required for load measurement. In the case of units designed with de-energized or on-load tap changers it is necessary to monitor the tap position in order to determine the internal losses at the operating condition. This data would be compared to the losses in the thermal model which are normally calculated at the worst case or highest loss position. It should be noted that depending on the design of units with taps in the high voltage winding, or in the case of the location of the auto-point connection in auto transformers, the maximum loss position will need to be determined from a review of the winding diagram with subsequent correction of the thermal test data. These monitored data would be entered into a computer-based program for comparison with the equivalent model parameters and the appropriate loading units and loss of life calculations would be made. XIV. Conclusion: Dynamic Loading of Transformers - Future Utility deregulation is changing the way transformer and other substation assets are utilized. Due to financial drivers, utility planners are striving to get more load capability from aged transformers. Dynamic loading of transformers means more than setting loading criteria based on varying load and ambient cycles. Re-rating transformers to operate above nameplate rating requires establishing maximum acceptable load criteria in the form of internal transformer temperatures, ancillary equipment capability, insulation loss of life criteria, and in real-time calculation, the maximum optimum load. In order to effectively implement such a program, several important steps should be followed.

1) Condition Appraisal -

• Benchmarking and ranking of units • Ancillary equipment evaluated for capability • End-point criteria of life identified

2) Load Optimization – Development of Thermal Models

• Criteria Set % Loss of life, maximum temperatures • Ancillary equipment temperature rise and current capability • Transformer thermal model and aging criteria established • Database Management of thermal modes

3) Dynamic Loading Program - • Use of temperature sensors for top, bottom, hottest spot, ambient, LTC

Compartment along with HV and LV PT’s and CT’s and tap position indicator • Algorithms for transformer model developed for computing future scenarios • Monitor would compare loading, oil and ambient temperatures to loss of life

and temperature limits in real time • Calculation of cumulative loss-of-life done continuously i.e. Insulation Life

Dosimeter The dynamic loading program would consider all the transformer and outside factors that influence hottest spot, top oil temperatures and loss of life and establish the upper loading limits of the transformer in real time. This loading would be established for normal life loading, planned loading beyond nameplate, long-time emergency loading and short-time emergency loading. This dynamic loading would give the operators specific information on the loading capability of the transformer under any existing or future condition. Dynamic loading programs would make the most effective use of a specific transformer and potentially give the operator real time information on how to balance the load for all units on the system.. Electric T & D companies are revising long standing loading policies and moving toward dynamic limits for normal and contingent operation. The need to analyze temperature rise and loss of life criteria for various operation parameters will lead to the opportunity to install intelligent monitoring systems.

The addition of real time monitoring for dynamic loading, and the ability to forecast optimum operating performance, is essential to meeting today’s competitive operating requirements and will have an immediate impact on financial goals. Incremental normal and contingent load capability, increased insulation system life and less risk of sudden failure are all combined benefits of the move toward dynamic loading of power transformers discussed in this paper.

REFERENCES

1. US Department of Commerce Data 2. NERC/IEEE Statistical Data, 1996 3. IEEE/ANSI C57.91 – 1996, “IEEE Guide for Loading Mineral-Oil Immersed

Transformers”. 4. IEC 354: 1991, “Loading Guide for Oil-Immerse Power Transformers”. 5. Allen, Professor D.J., “Transformer Reliability by Design”, TechCon 1996, New Orleans,

LA. February 1-2, 1996. 6. McNutt, Bill, ESERCO Report, 1989. General References

IEEE/ASNI C57.119 – 1996, “Recommended Practice for Performing Temperature Rise Tests on Oil-Immersed Power Transformers at Loads Beyond Nameplate Ratings”.

Pierce, Linden W., “Predicting Liquid Filled Transformer Loading Capability”, 1992 at IEEE IAS Petroleum and Chemical Industry Technical Conference. September 28-30, 1992.

Moore, Harold R., “Use of Oil Testing to Determine Transformer Condition and Life Extension”, TechCon 98, New Orleans, LA. February 16-18, 1998. David J. Woodcock and Jeffrey C. Wright, P.E., Power Transformer Design Enhancements Made to Increase Operation Life, Sixty-Sixth Annual International Conference of Doble Clients, April 12-16, 1999. Dave J. Woodcock and Michael A. Franchek, Life Cycle Considerations of Loading Transformers Above Nameplate Rating, Sixty-Fifth Annual International Conference of Doble Clients, April 1998.