JI YES
Scenario 1 Scenario 2
7.4.3 Break-Even Cost of Unsupplied Energy
The capital required to purchase a CT is R 185 500.The annual cost of capital is CostRefurbishment Project
=
R 185 500* 0.0738=
R 13 690 per annumEvery time one of these CTs failed, the CT and some of the adjacent equipment had to be replaced at an average cost of R 160 000 per event. If the CT is refurbished then there will be a saving of (R 160000* 0.0625 =R 18 750).
CostSavings = (R 160 000*(0.00846 +0.0253))= R 5402 per annum
The total energy not supplied due to the constraints of the existing CT (summation of all the EENS from the Table 7.4 above).
EENS
=
(1 269 + 591)=
1 860 kWh per annumThe break-even cost of unsupplied energy (BECOUE) is calculated as:
BECOUE = R(13 690 - 5 402)11 860 kWh
= R 4.46 IkWh
Since the BECOUE (R 4.46 IkWh) < Cost incurred to the customer (R 6.95IkWh) in the event of a failure, the replacement of the CT bellows is justified.
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7.5 Case Study 3 - Power Transformer Replacement
At Everest substation the maintenance costs for the 500 MVA 400/132 kV transformer has doubled over the last three years. Acid level tests,dissolved gas and furanic analysis were carried out to determine ageing and condition of the paper insulation. After 25 years of service, the results indicate that there is a need to replace the existing transformer with two new 250 MVA units in order to reduce operating maintenance costs and enhance station reliability.
Due to operating and maintenance cost records being mislaid,experienced field staff were consulted to obtain an estimate of average annual values that can be used in the justification calculations. The necessary data required and obtained is given below.
Expected energy at risk
Average maintenance Costold trfrper year Average maintenance Costnewtrfrsperyear CostNewtransformers
Cost of unserved energy (Industrialload)
=400 MW
=R750 000
=R11 000/ transformer
=R10 million
=
R17/ kWhPerformance data and component populations surrounding the transformer in this utility is tabulated in Table 7.6.
Average No. of
Component Probability of
Item Occurrences[3] Occurrence
(per annum) Population (%per annum)
Severe
5.34 328 1.628
Failures
Other Failures 12.67 295 4.295
Protection
58.0 295 19.661
Trips Busbar
38.4 207 18.569
Isolations
Table 7.6: Probabilityof occurrence-power transformer failure.
(3) Averagenumber of occurrencescalculatedover arecent 3-year period.
7.5.1 Probabilities Used
Firstly, the various scenarios for which the in-service transformer may be out of service is established based on following information:
•
•
•
•
•
Severe failure which requires that the unit be removed from site for possible repairs or to be replaced by a strategicspare unit (6 to 9 weeks).
Failure which involves an on-site repair(7 to 10 days).
Transformer protection trip with no permanent fault detected (1 to 2 hours).
Transformer maintenance (9 hours for a diverter switch and 15 hours for the transformer bays each year).
HV or MV/LV busbar isolation (1 hour)
With the performance data given, it is possible to calculate the probability of the power transformer being out of service.This probability is calculated as follows.
Pout of service
=
[((1.628+100) * 1008 hrs) + ((4.295+100) * 168 hrs) +((19.661+100) * 1 hr) + ((18.569+100) * 1 hr) + (9+15 hrs) + 8760 hrs]
=
0.005481The probability of the old transformer being out of service per annum is 0.5481 % or 48.013 hrs.
7.5.2 Break-Even Cost of Unsupplied Energy
The capital required to purchase the two transformers is R 10 000 000. The annual cost of capital is
Cost RefurbishmentProje ct
=
R 10000000*0.0738=
R 738 400 per annumIf the single unit is replaced,the cost to maintain the new transformers (R 22 000 per annum) are far less in comparison to the existing unit (R 750 000). The corresponding savings is
Cost Savings = (R 750 000 - 22 000) =R 728 000 per annum
The total energy not supplied as a result of any possible failure discussed above is EENS = 400 MW * 0.005481 =2 192 kWh per annum
The break-even cost of unsupplied energy (BECOUE) is calculated as BECOUE = R (738 000 - 728 000)12 192 kWh
= R 4.56/kWh
The investment of R 10 million is thus justified since the cost to the customer (R171 kWh) in the event of a failure is greater than the calculated BECOUE value of R 4.56 IkWh.However,operational cost savings need to be verified for final acceptance.
7.5.3 NPV Calculations
The Net Present Value (NPV) calculations were done for each option to determine which of the two options is the most suitable in terms of operational cost. The results for the installation of the new transformers and the old transformer presently in service are presented in Table 7.7.See Appendix I for NPV calculation.
Option 1 Option 2
Do Nothing Replace
Net Present Value
R' (000) 10338 10303
Table 7.7.Net present value comparison of transformer replacement versus no replacement.
121
From the above results it is clearly evident that option 2 (to replace) is preferred. In this case the operational cost savings were not significantly high enough to obtain final acceptance.
7.6 Case Study 4 - Circuit Breaker Refurbishment
At Pegasus substation two 400 kV minimum oil restriking feeder circuit breakers need to be replaced. The option to replace the oil feeder breakers with existing SFs bus section and bus coupler breakers located at Pegasus was accepted after carefully evaluating various solutions. Two spare minimum oil breakers located at a station in close proximity would then replace the bus section and bus coupler breakers. These spare oil breakers have no history of restriking while being in service for 34 years. Both the breakers would have to be transported to the new site and then overhauled. The total capital cost of the project is approximately R 1.55million.
By substituting and overhauling the breakers as proposed, substantial savings in terms of operational costs were foreseen. The economic justification was based on operational or maintenance cost reduction.This was determined as follows.
7.6.1 Operational Savings
The minimum oil feeder breakers are being replaced with existing SFs type, therefore, all future expenditures that would be required to maintain these breakers is considered as savings. A summary of these costs are given in Table 7.8.
Activity Maintenance Cost! breaker Maint. Cost! 2 Breakersl yr
PMT R 35 000 / 3vrs R 23500 /vr
MOT R 75 000 /12vrs R 12 500 /vr
TOTAL (1) R 36000 /vr
PMT
=
Periodic Maintenance&Testinq MOT=
Maior Overhaul &TestinaTable 7.8:Breakdown of maintenance costs for the400 kV minimum oil feeder breakers.
In the event of an oil breaker failing violently,there would be damage to surrounding plant equipment. Possible equipment that may be damaged and the cost to replace these items are listed in Table 7.9. However, the total approximate cost of a catastrophic failure is based on the probability of such an event occurring.
The probability of failure P(f), was calculated using the following performance data obtained:
Total number of restriking breakers in the entire network =7, Number of violent failures
=
3in 8years.Probability of failure - P(f)
=
(3/7)*(1/8)=
0.05357/yrQuantity Equipment Item Cost of Equipment
1 400 kV CircuitBreaker R 1500 000
3 Sinqle Phase CTs R 600 000
3 Motorised Isolators R 100 000
1 Labour R 100 000
TOTAL R 2300000
Breakdown Cost due toRestriking (Violent Failure) R 2300 000 * P(f)
TOTAL(2) R 123 211/yr TOTAL COST (1)+ (2) R 159 211/yr
Table 7.9: Cost of a breakdown in the event of a 400 kV minimum oilfeeder breaker failing catastrophically.
7.6.2 Operational Expenses
The cost to maintain the existing SFs breakers are not taken into consideration since they remain unchanged.The planned maintenance cycle of the spare oil breakers differs from the installed oil feeder breakers. These costs shown in the Table 7.10 would be regarded as the only additional expenses as a result of the changes being made. The cost to maintain these breakers wouldnot change and is on-going.
Activity Maintenance Cost! breaker Maint. Cost! 2 Breakersl yr
PMT R 35 000I 4yrs R 17500Iyr
MOT R 75 000I12yrs R 12 500Iyr
TOTAL EXPENSES R 30000 /vr
PMT=Periodic Maintenance&Testino MOT=MaiorOverhaul&Testing Table7.10: Breakdown of maintenancecosts for the spare minimumoil feeder breakers.
7.6.3 Capital Expenditure (Justifiable Amount)
• For an NDR of 6% and the write-offperiodbeing 25 years,the CRF = 0.0738.
• Net Savings
• Justifiable Amount
= Total Savings- Total Expenses
= R 159 211- R 30 000
= R 129 211 /yr
=
Net Savings/CRF= R 129211 /0.0738
= R 1 750826
The project is thus justified since the capitalamount required is estimated to be 1.55 million Rands.
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7.7 Case Study 5 -Replacement of a Failed Power Transformer
At Croydon substation (near Johannesburg) a 500 MVA 400/132 kV transformer failed catastrophically after being in service for 38 years.After 27 years of operating, gas-in-oil tests indicated a high moisture content in oil of approximately 25 ppm (c.f.
20 ppm limit as defined by IEEE [7,8]. The dielectric strength of the oil was reduced to 52 kV (as determined by international standard [12]; a technique using a 2.5mm gap spacing). Three years later (i.e. after 30 years of service) the oil was reprocessed, an on-line dry-out system and a rubber bag was retrofitted to prevent further moisture ingress through the conservator. This led to a further 8 years of service before failure. The transformer was replaced at total cost ofR 10million.
The replacement of the transformer was justified based on operational cost savings.
An estimate of average annual maintenance cost values was used in the justification calculations. These values together with the energy at risk and the cost of un-served energy for an industrial load are presented in Table 7.11.
Expected energy at risk =400 MW Average maintenance Cos4xistinQtrfrper year = R740 000 Average maintenance Costnewtrfrs per year =R10000 Cost of unserved energy (Industrial load) =R17/ kWh
Table 7.11: Maintenance costs (existing and new transformer), energy at risk and cost of unserved energy.
7.7.1 Probabilities Used
The probability of the transformer being out service is 0.005481 per annum. See 7.5.1 for an explanation.
7.7.2 Break-Even Cost of Unsupplied Energy
The capital required to purchase the new transformer is R 10 000 000. The annual cost of capital is
Cost Refurbishment Project=R 10 000 000 *0.0738=R738 400 per annum
If the single unit is replaced,the cost to maintain the new transformers (R 10 000 per ann.um) !s far less in comparison to the existing unit(R 740 000).The corresponding savings IS
Cost Savings =(R 740 000 - 10 000)=R 730 000 per annum
The total energy not supplied as a result of any possible failurediscussed above is EENS
=
400 MW * 0.005481=
2 192 kWh per annumThe break-even cost of unsupplied energy (BECQUE) is calculated as BECOUE
=
R (738 000 - 730 000)/2 192 kWh= R 3.64/kWh
The investment of R 10 million is thusjustified since this value it is lower than cost of un-served energy specified in Table 7.11.However,operational cost savings had to be verified for final acceptance.
7.7.3 NPV Calculations
The Net Present Value (NPV) calculations were done for each option to determine which of the two options is the most suitablein terms of operational cost. The results for the installation of the new transformer and the existing transformer presently in service are presented in Table 7.12.See AppendixJ for NPV calculation.
Option 1 Option 2
Do Nothing Replace
Net Present Value
10337 10137
R' (000)
Table 7.12: Net present value comparison of transformer replacement versus no replacement.
With reference table 7.12 it is clearly evident that option 2 (the replacement) is justified.
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CHAPTER 8: DISCUSSION
There is an increasing need for power utilities to increase the utilisation of their assets while maintaining system reliability. Asset or equipment reliability not only affects the availability of power to the customers, but also affects the economic operation of the utility. Substantial economic benefits can also be realised by maintaining and repairing equipment based on condition and operating them beyond their expected life.Because of this economic incentive, condition assessment of plant equipment and associated systems is essential. Key components of condition assessment are condition monitoring or diagnostic techniques that are employed as a means of verifying the condition for replacement/refurbishment or identifying failure or malfunction modes.
It has been established thus far that there are a number of techniques available or currently under development that can be used to assist in performing equipment assessment. However,the emphasis on special test and monitoring techniques for transformers and circuit breakers differ.
Power transformer condition evaluation is possible through some unique methods that are still being refined; however, the emphasis is being placed on more established means. Off-line testing techniques are still relied upon as the most dependable methods. It is also evident that some feasible techniques to monitor units while in-service and on-line are being made available.
There are several factors such as dielectric strength, acidity, colour of oil, dissipation factor, etc, that may reveal the condition of the transformer windings.This may be obtained via oil sampling and analysis.
Dissolved gas analysis remains the key assessment technique in determining the condition of power transformers.On-line gas analysers are available and need to be considered for application on high risk and transformers exhibiting unhealthy signs, requiring constant surveillance and nursing to a planned intervention levels and concentrations is now possible.
Partial discharge detection and localisation by acoustic means is available commercially and is being implemented with some success. The experimental results obtained in chapter 6.0is confirmation thereof.
Experimental findings (chapter 6.0) show that when acoustic emission and gas-in-oil (on-line) data are used in conjunction,early warning and diagnosis is enhanced. As the combination of information produced by these two techniques is advantageous,it is recommended that on-line, if possible or conventional gas analysis results be taken into account when interpreting partial discharge measurements.
Techniques such as recovery voltage measurement and furfural content in oil will become an extremely valuable means of approximating the unit's remaining operational lifespan. Furanic analysis from oil samples is one test that should be conducted on all transformers to ascertain the present state of health of the insulating paper.Subsequent tests will allow the projection of remaining insulation life.
The detection of abnormalities in transformer windings is being established by off-line techniques such as frequency response analysis. On-line techniques to detect winding displacement continue to be researched.Vibration monitoring has proven to
be a useful tool in determining the mechanical integrity of windings. which may be infrared scanning,although not new,are being further enhanced.
As a result of a large number of catastrophic failures occurring in a number of high voltage free-standing current transformers, there has been some experimentation with sensors for on-line monitors. Leakage current sensors (to measure capacitance and dissipation factor), acoustic sensors (to detect partial discharges) and hydrogen sensors (to detect hydrogen in oil levels) have been developed:
It may be difficult to financially justify the replacement of old technology breakers such as airblast, bulk oil and minimum oil types. However, refurbishment (life extension) or replacement decision may be achieved by some means of condition monitoring to determine condition. Condition monitoring is regarded as the ideal diagnostic tool to identify imminent failures in circuit breakers.
Key questions asked are: Do circuit breakers generally require a sophisticated condition monitoring system monitoring every possible parameter? A vast amount of data would need to be processed and there is the law of diminishing returns. The meaning of too much of data may become obscure. Continuous, on-line condition monitoring may yield returns only on breakers which operate relatively frequently, otherwise inspections of breakers may have more meaning.
The life of a transformer can be substantially extended by controlling the characteristics of the internal system i.e. controlling the oxygen and water contents.
By improving the utilization of the transformer capacity the condition of the paper insulation can be maintained.
There is very little that can be done to extend the life of the internal components of instrument transformers. However, certain maintenance practices and techniques may contribute to extending life.
With regard to extending the life of circuit breakers,various factors need to be taken into consideration. These are inspection, maintenance, service history, failure of similar breakers in service, and the availability of uprating and modification kits.
However, the decision to modify or uprate the breaker must be financially justified.
Five case studies have been presented in detail to demonstrate the financial techniques that can be applied to justify the refurbishment or replacement of HV plant equipment in concern. Only four of the five were economicallyfeasible projects.
127
CHAPTER 9: CONCLUSIONS
A literature review was carried out to establish the available and developing monitoring or diagnostic techniques to determine the condition of major high voltage plant equipment. Power transformers were the focus of this study.The findings of the study were as follows:
• The age of plant equipment is a poor indicator of condition.
• Diagnostic tests are required to accurately assess condition to decide on refurbishment or replacement.
• No single technique exists that would guarantee the condition of equipment;
however, a combination of reliable techniques would allow for vastly improved prediction of failure and decision taking.
An experiment was developed to examine issues related to condition assessment of electrical power equipment. These issues included investigating:
(1) The sensitivity of the electrical and acoustic detection to partial discharge inception voltage,and the corresponding measured PD magnitude;
(2) The detection and verification of the location of a fixed PD source;and
(3) The correlation between gas-in-oil measurements (on-line) and acoustic and electric emission data. A small scale experimental arrangement that is representative of power transformers in the field was used to investigate these issues.The test object was a small distribution transformer fitted with a point-to- sphere electrode geometry within the tank. The point anode comprised a stainless steel needle with a tip radius of 20 microns and the cathode;
consisting of a 60mm brass sphere. The point-to-sphere gap lengths were varied from 20 to 50mm. When a test voltage was applied to the point anode, partial discharges were produced under oil and measurements were taken for different gap lengths. The electrical detection and measurement system was calibrated according to the method described in IEC 270. Electrical PD detection is a well-known and established technique. From the experiment the following conclusions can be drawn:
• The detection threshold (partial discharge inception voltage) for the acoustic technique is 20% higher than the established electrical detection technique for the particular experimental arrangement used in this work.
• For the acoustic measurement technique the mean value for the PDIV achieved is 10.78 kV. This voltage corresponds to a PD magnitude of approximately 1000 pC.
• The partial discharge sensors are more sensitive than gas sensing technology,either on-line (hydrogen)or off-line (DGA).
• Partial discharge detection and localisation by a combined electrical and acoustic system is effective. By placing the acoustic sensors at various locations on the transformer tank, the position of the discharge can be
estimated by measuring the signal amplitude and absolute arrival time to the sensors. The acoustic signal received with the highest amplitude and shortest duration arrival time would mean that the discharge is in close proximity.
• A small increase in dissolved hydrogen was observed at the end of the experiment therefore, a correlation between gas-in-oil measurements (on- line) and acoustic emission data could not be established.
Plant items requiring substantial amounts of capital for refurbishmenUreplacement or life extension can be economically justified based on the application of proposed justification methods. In order to demonstrate the use of the financial justification techniques and to enhance understanding, five case studies were presented and explained in detail. These methods were applied successfully.
129
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