Power Quality Blog

Energy Efficient Distribution Transformers

Published by Mariusz NAJGEBAUER, Krzysztof CHWASTEK, Jan SZCZYGŁOWSKI,
Institute of Power Engineering, Częstochowa University of Technology

Abstract. The paper presented the possibilities of improvement in properties of electric distribution transformers through the use of new soft magnetic materials, mainly amorphous alloys, as transformer cores. The properties of amorphous were compared to conventional electrical steel sheets. Economic and pro-ecological advantages resulting from application of amorphous distribution transformers in electric power systems were considered.

Streszczenie. W pracy przedstawiono możliwości poprawy właściwości transformatorów rozdzielczych poprzez zastosowanie w nich rdzeni z nowych materiałów magnetycznych, głównie stopów amorficznych. Właściwości stopów amorficznych zostały porównane z właściwościami blach elektrotechnicznych. Przeanalizowano ekonomiczne i proekologiczne korzyści wynikające z wykorzystania transformatorów rozdzielczych z rdzeniami amorficznych w systemach elektroenergetycznych. (Możliwości poprawy właściwości transformatorów rozdzielczych)

Keywords: distribution transformers, energy savings, investment profitability, environment protection.
Słowa kluczowe: transformatory rozdzielcze, oszczędność energii, opłacalność inwestycji, ochrona środowiska.

Introduction

Distribution transformers are units of electric power systems, in which electricity is transformed form the voltage level 1 – 50 kV to the voltage level 120 V + 1 kV, in dependence on consumers’ needs. Energy efficiency of distribution transformers is very high, typically ranging between 96% and 99%. However, due to a large number of distribution transformers in electric power system and their long lifetime (30 – 40 years), even small improvement in the efficiency of these units could result in significant energy savings [1]. These issues are important both from economic and ecological viewpoints.

Increase of energy efficiency of distribution transformers could be obtained reducing three types of transformer losses:

– no-load loss (iron or core loss) can be reduced by improvement in design and assembling processes or in magnetic properties of material core,
– load loss (copper loss) can be reduced increasing the cross-section of the windings,
– cooling loss can be reduced by decrease of other types of transformer losses [1].

Further increase in transformer efficiency is possible to reach by replacement silicon steel cores with new types of magnetic core materials, e.g. amorphous ribbons.

Amorphous materials were developed in the seventies of the last century. These materials are produced by rapid solidification of a liquid alloy, what gives specific magnetic properties, especially very low energy loss. However, these materials have quite low saturation induction and they are thermal unstable. Production technology and properties of amorphous materials were described in detail in earlier authors’ papers [2-8]. The properties of amorphous alloy and commonly used silicon steel are compared in Table 1.

Table 1. Chosen properties of transformer core materials [9]

Construction of amorphous transformers

Amorphous cores are usually produced as wounded, one-side cutting ones, due to mechanical properties of amorphous ribbons. This solution ensures the correct location of air gaps inside a core and simplifies electric windings assembling as well [2,7,11]. Amorphous transformers are produced as 1-phase or 3-phase units, with 3-limbs or 5-limbs core construction [2,7,9]. The capacity of currently produced amorphous transformers is limited up to 10 MVA [1]. The construction of an oil immersed type amorphous transformer produced by Hitachi Corporation, which is representative for this kind of transformers, is presented in Figure 1.

Fig.1. 3-phase amorphous transformer (1000 kVA, 6 kV/210 V, 60 Hz): 1 – 3 limbs core, 2 – coil, 3/4 – primary/secondary bushing, 5 – tank [9]

The cross-section of amorphous cores is larger in comparision to silicon steel ones, due to lower saturation induction of amorphous ribbons. It results in the increase of transformer dimensions and weight. Dimensions and weight of silicon steel core and amorphous core transformers are compared in Table 2.

Table 2. Transformer dimensions and weight [9]

SiT – 3-phase silicon steel core transformer, 1000 kVA, AMT – 3- phase amorphous core transformer, 1000 kVA *with relation to SiT

Energy savings and economic profits of amorphous transformers

No-load loss of amorphous core transformers is very low comparing to conventional transformers with silicon steel core. It results from very low energy loss of amorphous ribbons and also its small thickness, what significant reduces eddy currents flow. The reduction of no-load loss in amorphous transformers is estimated at 70% – 80% [2-14]. The following Tables 3-6 present the reduction of energy loss in amorphous transformers, produced by different companies.

Table 3. Energy loss in silicon steel and amorphous transformers, 6,6 kV/210 V, 60 Hz, produced by Hitachi Co. [9]

Table 4. Energy loss in silicon steel and amorphous transformers, produced by ABB Group [15]

Table 5. Energy loss in silicon steel and amorphous transformers, produced by Transformateurs Ferranti -Packard Ltée [16]

Table 6. Comparison of no-load loss in silicon steel (SiT) and amorphous transformers (AMT) [17]

*reduction of no-load loss with relation to SiT (in-service)
**reduction of no-load loss with relation to SiT (best)

It is estimated, that currently over 83 million distribution transformers operate in six biggest economies in the world, including 3,6 million units in UE-25 countries [18,19]. Thus, a worldwide potential of energy savings, through the use of amorphous transformers instead of the conventional ones seems to be significant. There are a lot of estimations of energy savings, worked out by transformer producers, government and non-government institutions, as European Commission [20], US Department of Energy [21], European Copper Institute [18,19], with Leonardo ENERGY and ProPHET (Promotion Partnership for High Efficiency Transformers). The estimations of annual transformer loss and potential energy savings for six biggest economies are given in Table 7.

Table 7. Annual transformer loss and potential energy saving through the use of amorphous transformers [21]

It is obvious that energy savings in transformers give economic profits. The Cost Saving Effect (CSE) could be calculated from a simple relation

where: CP_SiT/AMT– cost of annual loss in silicon steel or amorphous transformer in [USD/year], given by

where: NLL – no-load loss [W], LL – load loss [W], LF – load factor, ECh – electric charge in [USD/kWh] [9].

For a typical 3-phase 100 kVA transformer, e.g. listed in Table 3, under the assumption ECh = 0,01 USD/kWh and LF = 0,5 [9], it was obtained from calculations that CP_SiT = 1 144,81 USD/year and CP_AMT = 811,81 USD/year. Thus, CSE in case of a single amorphous transformer is equal to 333,20 USD/year (own calculation, based on [9]). Considering a large number of distribution transformers, the potential Cost Saving Effect through the use of amorphous units is estimated at billions of US dollars each year.

The economic analysis of the investment in amorphous transformer technology could be based at Total Owning Cost (TOC). The TOC coefficient encompasses the initial cost of the transformer and the future cost of the no-load and load losses over its lifetime [10]. Amorphous transformers are 30 – 50% more expensive than silicon steel ones [10,22]. Nevertheless, the significant reduction of no-load loss in amorphous transformers provides TOC benefit over transformer lifetime, what is presented in Figure 2. It indicates the amorphous transformers as better solution.

Fig.2. Diagram of Total Owning Cost [10]

The calculation of the TOC factor for the typical 500 kVA and 1000 kVA silicon steel and amorphous distribution transformers are presented in Table 8.

Table 8. The calculation of the TOC factor for silicon steel and amorphous transformers [own calculation, basing on 11]

Ecological profits of amorphous transformers Wider application of amorphous transformers in electric power systems gives not only energy savings and economic profits. This process has also ecological aspects. Significant energy savings result in decrease of fuel consumption in power plants, what reduces the emission of greenhouse gases. This issue is important form social considerations and for economic policy, because it simplifies the fulfilment of the international agreements of environment protection.

The Reduction Effect of CO₂ emissions (RE_CO2) could be calculated form the following relation

where: E_{CO2_SiT/AMT} – annual CO₂ emissions of silicon steel or amorphous transformer in [t/year], given by

where: EC_CO2– CO₂ emission coefficient [kg/kWh] [9].

In case of 100 kVA transformer and for the emission coefficient EC_CO2 = 0,555 kg/kWh, the reduction of CO₂ emissions is equal to RE_CO2 = 8,9 t/year [9]. The potential reduction of greenhouse gas emissions through the use of high efficiency amorphous transformers is given in Table 9.

Table 9. Environmental impact of amorphous transformers [11,18]

*estimation of Leonardo ENERGY (European Copper Institute)
**estimation of US Environmental Protection Agency

Conclusions

High efficiency distribution transformers with amorphous core become more and more popular. At present, there are more than 1,5 million amorphous transformers operating worldwide. Each year, 10% – 15% of new transformer sales in USA and Japan are amorphous ones [22]. The increasing number of amorphous transformers results both from energy savings and reduction of greenhouse gas emission. Only in the countries of European Union, annual energy savings are estimated at 18,5 TWh, corresponding to 1€ billion saving in operating cost. The energy savings are equivalent to the annual production of three nuclear power stations (1 000 MW) or eleven fossil fuel power units (350 MW) [1].

The energy savings from amorphous transformers have a great influence on the scope of electricity production and consumption. Thereby, this issue should be considered in forecasting models applied in electric power engineering.

REFERENCES

[1] Targosz R., Energy efficient distribution transformers, Brochure of Leonardo ENERGY, 2009, 4s. http://www.leonardoenergy.org
[2] Najgebauer M., Chwastek K., Szczygłowski J., Modern soft magnetic materials in “environment-friendly” transformers cores, Przegląd Elektrotechniczny, 12 (2003), 930-932
[3] Chwastek K., Najgebauer M., Szczygłowski J., Proecological aspects of progress in soft magnetic technology and its effect on power engineering, Technology & Economy in Industrial Reconversion, ISI Pierrard, HEC du Luxemburg, Virton, Belgia, 2004, 66-70
[4] Najgebauer M., Szczygłowski J., Pro-ecological aspects of soft magnetic materials applications in power transformers, The Challenges for Reconversion: Innovation-Sustainability-Knowledge Management, ISI Pierrard, HEC du Luxemburg, Virton, Belgia, 2006, 157-165
[5] Najgebauer M., Szczygłowski J., Nowoczesne tendencje rozwojowe w inżynierii materiałów magnetycznych, VI Semi-narium Naukowe WZEE’2006, Lublin, 2006, 41-50
[6] Szczygłowski J., Progress in Soft Magnetic Materials for Industrial Applications, Proceedings of IV^th International Scientific Symposium „Elektroenergetika 2007”, Słowacja, 2007, 350-354
[7] Najgebauer M., Szczygłowski J., Transformatory energetyczne z rdzeniami amorficznymi, Przegląd Elektrotechniczny, 12 (2007), 108-111
[8] Chwastek K., Najgebauer M., Szczygłowski J., Wilczyński W., Modern core materials for efficient power distribution transformers, Przegląd Elektrotechniczny, 3 (2009), 133-135
[9] Hitachi amorphous transformers, Brochure of Hitachi Industrial Equipment Systems Co., Ltd., 2008, http://www.hitachi-metals.co.jp/e
[10] http://www.metglas.com
[11] DeCristofaro N., Amorphous metal in electric power distribution applications, MRS Bulletin, 23 (1998), 50-66
[12] Junyi L., The development of amorphous distribution transformers in China, Proceedings of International Conference TEAMT’2004, 2004, 313-318
[13] Hasegawa R., Energy efficiency of amorphous metal based transformers, Proceedings of International Conference TEAMT’2004, 2004, 219-223
[14] Shibata E., Pursuit of higher efficiency of transformers in Japan, Proceedings of International Conference TEAMT’2004, 2004, 300-304
[15] The transformer with low losses. The amorphous metal transformer, Brochure of Asea Brown Boveri, http://www.abb.com
[16] Schulz R., Alexandrov N., Tétreault J., Simoneau R., Roberge R., Development and application of amorphous core-distribution transformers in Québec, Journal of Materials and Engineering and Performance, 4 (1995), 430-434
[17] Hasegawa R., Present status of amorphous soft magnetic alloys, Journal of Magnetism and Magnetic Materials, 215-216 (2000), 240- 245445
[18] Targosz R. (edit.), The potential for global energy savings from high efficiency distribution transformers, Brochure of European Copper Institute, Belgium, 2005
[19] Targosz R., Topalis F.V., Energy efficiency of distribution transformers in Europe, Proceedings of 9^thInternational Conference on Electrical Power Quality and Utilisation, Barcelona, 9-11.10.2007, 2007, 5s.
[20] The scope for energy saving in the EU through the use energy efficient electricity distribution transformers, Brochure of European Commission, Belgium, 1999
[21] Hasegawa R., Azuma D., Impacts of amorphous metalbased transformers on energy efficiency and environment, Journal of Magnetism and Magnetic Materials, 20 (2008), 2451-2456
[22] Frau J., Gutierrez J., Energy efficient distribution transformers in Spain: new trends, Proceedings of 19^th International Conference on Electricity Distribution CIRED2007, Vienna, 21-24.5.2007, 2007, 4s.

Autors: dr inż. Mariusz Najgebauer, dr inż. Krzysztof Chwastek, dr hab. inż. Jan Szczygłowski, prof. PCz., Institute of Power Engineering, Częstochowa University of Technology, al. Armii Krajowej 17, 42-200 Częstochowa, Poland e-mail: najgebauer@el.pcz.czest.pl, krzych@el.pcz.czest.pl, jszczyg@el.pcz.czest.pl

Source & Publisher Item Identifier: PRZEGLĄD ELEKTROTECHNICZNY (Electrical Review), ISSN 0033-2097, R. 87 NR 2/2011

Impact of Capacitor Bank Outrush Reactors on Circuit Breaker Transient Recovery Voltages

Published by Electrotek Concepts, Inc., PQSoft Case Study: Impact of Capacitor Bank Outrush Reactors on Circuit Breaker Transient Recovery Voltages, Document ID: PQS0906, Date: October 15, 2009.

Abstract: Current limiting outrush reactors are often installed with utility transmission capacitor banks. These reactors limit the high-magnitude, high-frequency currents that flow when the capacitor bank discharges into a nearby fault. While an outrush reactor reduces the magnitude and frequency of the current during close-in faults, it may cause excessive transient recovery voltages (TRVs) for the capacitor bank circuit breaker due to the very high frequency component of the recovery voltage associated with the reactor. Excessive TRVs may cause the capacitor bank circuit breaker to fail to clear during certain fault conditions. An engineering study was completed to evaluate the TRVs for various capacitor bank circuit breaker operations, system contingencies, and mitigation alternatives. This case study presents a summary of the model development and simulations completed during the outrush reactor TRV study.

INTRODUCTION

Due to the concern for excessive transient recovery voltages (TRVs) during capacitor bank circuit breaker operations, an engineering study was performed to determine the impact of capacitor bank outrush reactors on circuit breaker transient recovery voltages. The study evaluated the concerns and possible solutions, including adding various amount of capacitance to reduce the rate-of-rise of the recovery voltage.

The analysis of high-frequency transient recovery voltages frequently requires the use of sophisticated digital simulation programs. Simulations provide a convenient means to characterize transient events, determine resulting problems, and evaluate possible mitigation alternatives. Occasionally, they are performed in conjunction with system monitoring for verification of models and identification of important power system problems. The complexity of the models required for the simulations generally depends on the system characteristics and the transient phenomena under investigation. The transient analysis for the engineering study was performed using the PSCAD/EMTDC Program (Version 4.2).

STUDY METHODOLOGY

The transient recovery voltage evaluation for various fault conditions was based on the methods provided in IEEE Std. C37.06, IEEE Std. C37.04, and IEEE Std. C37.011. This involved analysis of the most severe conditions, including the clearing of three-phase and single-line-to-ground faults at the capacitor bank circuit breaker and outrush reactor terminals when the system voltage is at a maximum.

The study included normal cases where the system operates with all circuit breakers and lines in service and various contingencies representing different operating conditions. For each case, three-phase ungrounded, three-phase grounded, and single-line-to-ground faults were evaluated.

The transient recovery voltage is the voltage across the terminals of a pole of circuit breaker following current zero when interrupting faults. Transient recovery voltage waveshapes can be oscillatory, exponential, cosine-exponential or combinations of these forms. Transient recovery voltages due to short-line faults (SLFs) are characterized by triangular-shaped waveshapes and a very steep initial rate-of-rise. The triangular shape of the recovery voltage arises from positive and negative reflections of the traveling waves that oscillate between the open circuit breaker and the fault. Due to the short distance involved, the initial rate-of-rise of the recovery voltage (RRRV) can be very steep.

According to IEEE Std. C37.011, the most severe oscillatory or exponential recovery voltages tend to occur across the first pole to open of a circuit breaker interrupting a three-phase ungrounded symmetrical fault at its terminal when the system voltage is at a maximum. When the transient recovery voltage performance meets the withstand criteria when subjected to the fault condition mentioned above, a short-line fault evaluation is not necessary. This is because short-line fault transient recovery voltage capability is higher than that of a three-phase ungrounded fault.

For conditions where the simulated transient recovery voltage exceeded the withstand capability of the circuit breaker, the mitigation option of added capacitance was also evaluated.

MODEL DEVELOPMENT

The model development process included steps for data collection, data approximation, data simplification, and model verification.

The TRV system model was based on short-circuit data that consisted of positive and zero sequence impedance data in the ASPEN Oneliner format. The study area included the substation and the adjacent system (see Figure 1). The boundary of the study area was represented with equivalent sources and transfer impedances such that the electrical representation of the study area (at 60 Hz) was nearly identical to the original representation.

Figure 1 – System Model for the 138kV TRV Study

In the study, all transmission lines were represented with a frequency dependent line model to account for traveling wave phenomena. Generating units were represented with ideal sources behind sub-transient impedances. The accuracy of the transient model was verified by comparing three-phase and single-line-to-ground fault currents at all buses. A subset of the fault cases is summarized in Table 1.

Table 1 – Steady-State Fault Simulations Completed for Model Verification

The model represented a reduction of the entire system to determine the system equivalents and corresponding fault levels. It should be noted that the corresponding PSCAD model did not include mutual coupling between transmission lines. In addition, typical X/R ratio values were used where the short-circuit model did not include resistance (e.g., lines, transformers, etc.), and relatively large transfer impedances were ignored. Considering these factors, accuracy within 3% was considered acceptable for the 60 Hz short-circuit model verification.

Circuit Breaker Data

The circuit breaker ratings and transient recovery voltage data included:

Rated Maximum Voltage: 145 kV
Rated Continuous Current: 3000 A
Rated Short-Circuit Current: 40 kA
Rated Interrupting Time: 3 Cycles
Line Charging: 160 A
Isolated Bank Switching: 315 A
Back-to-Back Switching: 315 A

Table 2 – Rated TRV Capability of 145kV, 3000 A, 40kA Breaker

The waveshape of the exponential component E1 for terminal faults below 30% of the breaker rating is 1-cosine. Based on Table 2 and the discussion in Section 5.9 of IEEE Std. C37.04-1999, the TRV limit envelopes were derived and graphically represented using a MATLAB program. Figure 2 shows the TRV envelopes (or withstand capabilities) for several fault levels. Capability envelopes when interrupting fault currents below 30% of its rated short-circuit current have a waveshape of 1-cosine, while for fault currents above 30% of breaker rating, the waveshape has an exponential-cosine form.

Figure 2 – TRV Withstand Capability for a 145kV, 3000 A, 40kA Breaker

Capacitance Values for Substation Equipment

Equivalent values of capacitance for substation equipment were based on the typical capacitance ranges provided in Annex B of IEEE Std. C37.011-1994. Three equivalent capacitance values (minimum, maximum, and average) were determined. Table 3 shows an example of the collection of typical capacitance values for each bus section in the substation. The minimum values of equivalent capacitance were used throughout the simulation process for both normal and contingency cases.

Table 3 – Typical Capacitance Values Based on Annex B of IEEE Std. C37.011-1994

Outrush Reactor Model

An outrush reactor was installed with the 138 kV capacitor bank to provide substation circuit breaker protection in the event of reclosing into a close-in fault. The reactor rating of 1.88 mH was based on the 145 kV general-purpose circuit breaker limitation (Ipk*f < 2×10⁷) in IEEE Std. C37.06-2000.

As shown in Figure 3, the 1.88 mH outrush reactor was modeled as a lumped inductance in parallel with a 51.5 ρF capacitance (value provided by the reactor manufacturer). This results in a natural frequency for the reactor of approximately 511 kHz:

where:
f is the natural frequency of the reactor (Hz)
L is the inductance of the reactor (H)
C is the capacitance of the reactor (F)

Also in parallel with the reactor were the minimum equivalent capacitance values of the connected equipment, including 25 ρF to represent an open circuit breaker, 300 ρF to represent two CTs, and 38 ρF to represent 15 feet of 138 kV bus. Therefore, the total equivalent capacitance included in the simulation model was 363 ρF. This capacitance added to the outrush reactor capacitance yields 414.5 ρF and results in a transient recovery voltage frequency of approximately 180 kHz:

Finally, a variable resistor was also connected in parallel with the reactor to represent the typical damping associated with the outrush reactor.

Basecase Model Development

Figure 4 shows a portion of the overall PSCAD circuit model used to determine the prospective transient recovery voltage withstand capabilities for the 138 kV capacitor bank circuit breaker when clearing various faults at the terminals of the outrush reactor under normal and contingency conditions. Transient recovery voltage, peak current interrupted, and the percentage of interrupted current (based on the short-time rating for the circuit breaker) was observed for each simulation case. Prospective transient recovery voltage waveshapes were then compared to their related capabilities by using a user-developed MATLAB program to graph the output from each PSCAD simulation case with an overlay of the transient recovery voltage envelope capability.

Figure 4 – Circuit for Applying Various Faults at the Outrush Reactor Terminals

Transient Recovery Voltage Evaluation Criteria and Simulation Cases

The outrush reactor limited fault creates a high frequency transient recovery voltage that the related ANSI/IEEE standards do not specifically address. For this study, the focus was on determining, and then reducing the reactor side component of the transient recovery voltage to meet the known ANSI/IEEE specified short-line fault capability for the 145 kV, 40 kA capacitor bank circuit breaker.

Criteria for the transient recovery voltage evaluation were based on IEEE Std. C37.011-1994, which states that evaluations should be conducted for three-phase ungrounded faults at the circuit breaker terminals when the system voltage is at maximum. The maximum voltage is 1.05 per-unit of the nominal voltage. The transient recovery voltage evaluation for the capacitor bank circuit breaker at the capacitor bank substation considered the following conditions:

during the clearing of a three-phase ungrounded symmetrical fault at the circuit breaker terminal when the system voltage is at the maximum (1.05 per-unit).
during the clearing of a single-line-to-ground fault at the circuit breaker terminal when the system voltage is at the maximum (1.05 per-unit).
during the clearing of a three-phase-ungrounded fault at the outrush reactor terminal.
during the clearing of a three-phase-to-ground fault at the outrush reactor terminal.
during the clearing of a single-line-to-ground fault at the outrush reactor terminal.

For conditions where the simulated transient recovery voltage exceeded the circuit breaker’s withstand capability, the mitigation option of added capacitance was evaluated. This included cases for various standard capacitance ratings, including 1,500 ρF, 2,500 ρF, 5,000 ρF, 7,500 ρF, and 10,000 ρF. Relevant transient recovery voltage and mitigation cases were repeated for a number of other outrush reactor ratings, such as 3.68 mH, 1.88 mH, 0.94 mH, 0.90 mH, and 0.20 mH. These cases were completed to determine the relationship between the reactor rating and the severity of the capacitor bank circuit breaker recovery voltages. Similarly, cases were completed to determine if a circuit breaker with a higher short circuit rating affected the results.

Finally, a number of transient recovery voltage and mitigation cases were repeated under several contingency conditions, such as the removal of the substation’s 345 kV/115 kV transformer.

SIMULATION RESULTS

The transient recovery voltage evaluation included both three-phase and single-line-to-ground faults at the outrush reactor terminals.

Reactor Terminal Faults

The simulation results for the various reactor terminal fault clearing cases were summarized in tables similar to Table 4. The table shows the respective case identifier, the fault type, the capacitance values, the peak current that the circuit breaker interrupted, this peak current as a percentage of the rated value (40 kA), the peak transient recovery voltage in kV, and a note to report whether the transient recovery voltage was within the circuit breaker’s capability envelope. A “YES*” note signifies that the transient recovery voltage waveshape slightly exceeded the transient recovery voltage capability for the first 10-50 μsec, but it met the transient recovery voltage short-line fault capability. A “NO” note signifies that the waveshape did not meet the transient recovery voltage capability limit.

Figure 5 and Figure 6 show several examples of the simulation results for the outrush reactor terminal fault clearing cases summarized in Table 4. Figure 5 shows the recovery voltage for the capacitor bank circuit breaker for Case C1 and Figure 6 shows the results for Case D1. Each graph includes the corresponding circuit breaker withstand capability.

Table 4 – TRV Evaluation of Reactor Faults

Figure 5 – TRV Withstand Capability for Case C1

Figure 6 – TRV Withstand Capability for Case D1

Evaluating Effectiveness of Added Capacitance

A number of cases were completed to evaluate resulting transient recovery voltages for the capacitor bank circuit breaker when clearing faults at the outrush reactor terminal under normal conditions with additional capacitances added at the reactor terminals.

The ratings of the additional capacitances simulated included standard ratings available from several manufacturers, including 1,500 ρF, 2,500 ρF, 5,000 ρF, 7,500 ρF, and 10,000 ρF. The additional capacitance adds to the outrush reactor and other equipment capacitances. For example, adding a 1,500 ρF capacitance results in a total capacitance of 1914.5 ρF and a transient recovery voltage frequency of approximately 84 kHz.

Figure 7 and Figure 8 show examples of the simulation results for a single-line-to-ground fault on the outrush reactor terminal. Figure 7 shows the recovery voltage for the capacitor bank circuit breaker with 1,500 ρF added and Figure 8 shows the results with 5,000 ρF added.

Figure 7 – TRV Withstand Capability for Case D1 with 1,500pF Added (Case E1)

Figure 8 – TRV Withstand Capability for Case D1 with 5,000pF Added (Case E3)

Evaluating Outrush Reactor Rating

Cases were completed to evaluate resulting transient recovery voltages for the capacitor bank circuit breaker when clearing faults at the outrush reactor terminal for a number of different reactor ratings, including 0.20 mH, 0.90 mH, 0.94 mH, and 3.68 mH.

Figure 9, and Figure 10 show examples of the simulation results for a single-line-to-ground fault on the outrush reactor terminal. Figure 9 shows the recovery voltage for the capacitor bank circuit breaker with a 3.68 mH reactor rating (no additional capacitance) and Figure 10 shows the results with a 3.68 mH reactor rating and a 10,000 ρF capacitance.

Figure 9 – TRV Withstand Capability for a 3.68mH Reactor

Figure 10 – TRV Withstand Capability for a 3.68mH Reactor with 10,000pF Added

SUMMARY

The engineering study included an evaluation of the transient recovery voltage performance of a 145 kV capacitor bank circuit breaker in a 138 kV substation. A number of observations and conclusions included:

1.The simulated transient recovery voltages exceeded the short-line fault capability limits when clearing three-phase ungrounded, three-phase grounded, and single-line-to-ground faults at the reactor terminals. This is because the recovery voltage severity is worsened by the very high frequency component of the transient voltage on the reactor side of the circuit breaker.

2.One method for improving this condition is with the application of an additional capacitance to ground between the circuit breaker and the outrush reactor. This capacitance reduces the severity of the transient recovery voltage. Standard capacitance ratings, including 1,500 ρF, 2,500 ρF, 5,000 ρF, 7,500 ρF, and 10,000 ρF, were simulated. The simulations indicated that the 5,000 ρF capacitance was the minimum standard capacitance rating that would reduce the recovery voltage to within the beaker’s capability for all of the cases.

3.The effect of outrush reactor rating on resulting transient recovery voltages was evaluated for the ratings 0.20 mH, 0.90 mH, 0.94 mH, and 3.68 mH. Only the 0.20 mH reactor rating had a transient recovery voltage waveshape that did not exceed the related short-line fault capability limit. A 10,000 ρF capacitance was required to reduce the recovery voltage to within the circuit beaker’s short-line fault capability for the 3.68 mH reactor rating.

4.Supplemental cases were completed to evaluate several contingency operating conditions. The severity of the transient recovery voltages was not changed significantly because the characteristic was dominated by the very high frequency component of the transient voltage on the reactor side of the circuit breaker.

REFERENCES

PSCAD, Version 4.0.2 Professional, http://www.pscad.com.
IEEE AC High Voltage Circuit Breakers Rated on a Symmetrical Current Basis – Preferred Ratings and Related Required Capabilities, IEEE Standard C37.06, May, 2000.
IEEE Standard Rating Structure for AC High-Voltage Circuit Breakers, IEEE Standard C37.04, June, 1999.
IEEE Application Guide for Transient Recovery Voltage for AC High Voltage Circuit Breakers Rated on a Symmetrical Current Basis, IEEE Standard C37.011, September, 1994.

RELATED STANDARDS
IEEE Std. C37.06, IEEE Std. C37.04, IEEE Std. C37.011

Stolen Electricity or Gas Meter?

Published by CallMePower | Selectra LLC

Has your electricity or gas meter been stolen? Find out here what to do if your meter has been snitched.

Why are meters stolen?

Electric meters contain electronic components which can be sold on the black market. Copper, an expensive metal with high conductivity, is usually present in electricity meters, although in small quantities. Gas meters may contain other parts of scrap metal which could be sold, although probably not at a great profit.

Meters can also be stolen in order for them to be installed elsewhere. The meter thief will install the stolen meter to a new location, so that the electricity used at that location is measured by the stolen meter. Every month, when the utility company’s technician comes to make a meter reading, the thief will replace the stolen meter with the original meter, to avoid suspicion. Indeed, the technician can identify the meter, and verifies it belongs to the correct address. This way, the electricity used will be counted by the stolen meter, and not the original meter.

Image: CallMePower | Selectra LLC – Meter theft

How are meters stolen?

Image: CallMePower | Selectra LLC – Stolen meter

Picture of 2 stolen electricity meters. On the left, only the central part of the meter has been taken, on the right, the whole box has been taken.

Meters are stolen by disconnecting all incoming and outgoing electrical cables (or pipes, for gas meters), and taking the box which contains all the meter parts. It can either be done in a clean manner, if the thief wishes to re-use the meter, or in a sloppy manner, by ripping the meter off the wall, usually for those only wishing to sell the scrap metal of the meter.

How to get your meter back?

First, you must report the meter theft. Call the outages phone number of your utility company, and and report the theft. If you have the meter number, give it to them. If not, your exact address and apartment number will suffice. A technician will be sent to inspect your meter location. If your meter has indeed been stolen, the technician will issue an order to replace it shortly. The delay for your meter to be replaced can vary depending on the utility company.

Wire Wrapping for Low Current Monitoring

Published by Veris Industries, Veris Application Note VN35 – Wire Wrapping for Low Current Monitoring.

The information provided herein is intended to supplement the knowledge required of an electrician trained in high voltage installations. There is no intent to foresee all possible variables in individual situations, nor to provide all training needed to perform these tasks. The installer is ultimately responsible to assure that a particular installation will be and remain safe and operable under the specific conditions encountered.

Introduction

Some conductors carry loads below the rating of standard current sensors. To monitor these conductors, employ a simple wire-wrapping technique to amplify the current sensor’s input.

Wrap the monitored conductor through the center hole and around the sensor body to produce multiple turns through the iris. This increases the current measured by the transducer.

The controller must then be programmed to account for this wrapping. For example, if the conductor passes through the sensor iris four times, the controller must divide the sensor reading by four to calculate the actual current in the conductor.

Wiring Example

In the example below, the sensor has a minimum current rating of 0.75A. The current in the conductor is only 0.2A. The conductor is therefore wrapped through the sensor’s iris 4 times.

sensor output / # of loops = conductor current

0.8A / 4 = 0.2A

Source URL: https://www.veris.com/ASSETS/DOCUMENTS/CMS/EN/Static_Documents/Application%20Notes/vn35.pdf

High Voltage Test Transformers, Construction, Design and Their Application in HV Testing System

Published by Bogdan TUŁODZIECKI, Electric Apparatuses Factory Zwarpol Ltd. in Warsaw

Abstract. In this article were described the most frequently used constructions of high voltage test transformers. There were presented defects, advantages and application of describing constructions. There were described how to design high voltage test transformers and what is important during their design. On the basis of measurements of selected high voltage test transformers were verified correctness of computational methods. During analysis of results were presented constructors’ problems connected with a design and making a product.

Streszczenie. W artykule opisano najczęściej produkowane konstrukcje transformatorów probierczych. Podano wady, zalety i zastosowanie opisanych konstrukcji. Opisano jak należy projektować i na co należy zwrócić uwagę przy projektowaniu. Na podstawie pomiarów wybranych transformatorów probierczych zweryfikowano poprawność metod obliczeniowych. Dodatkowo analizując wyniki przedstawiono problemy z jakimi napotyka się konstruktor podczas projektowania i wykonywania wyrobu. (Transformatory probiercze, budowa, projektowanie i ich zastosowanie w układach probierczych)

Keywords: high voltage test transformers, high voltage testing systems, strength of primary isolation, withstand tests
Słowa kluczowe: transformator probierczy, układ probierczy, wytrzymałość izolacji pierwotnej, próby wytrzymałościowe

1.Introduction

High voltage test transformers are single-phase solution of transformers, which have to raise supply voltage to required value to make a dielectric withstand test of liquid or solid insulation. The strength of primary insulation, minimum value of short-circuit voltage and increasing transformer voltage ratio to level when value of secondary voltage (high voltage), reducing of voltage drop on load by power rating, it wouldn’t smaller than set value is very important in high voltage test transformers. It is essential to calculate voltage and angular errors to adequate increasing of transformer voltage ratio of high voltage test transformer and describing its voltage of short circuit. Accuracy of transformation of voltage isn’t a desirable quantity. Value of secondary voltage in high voltage testing systems is determined by rodman branch or voltage high divider, so it isn’t necessary to command of nominal transformer voltage ratio. Calculation of parameters of high voltage test transformers isn’t easy. High voltage test transformers sometimes equip with branch or branches made on secondary winding for the sake of adapting of transformer to examination of isolation with different levels of voltages and different values of power of load. In this case one kind of coil wire can’t wind secondary winding. Besides, some high voltage test transformers have two primary windings, which are link/wired in series or parallel to change its nominal transformer voltage ratio. Calculation of parameters of these high voltage test transformers is more complicated than transformers with one primary winding. High voltage test transformers are characterized by many variety of solutions on different level of complexity.

In this article the author focus his attention concentrate on High voltage test transformers made by Zwarpol Factory Ltd., where he has been working. He describe their construction, design and application in high voltage testing systems.

2.Construction

High voltage test transformers find application in high voltage testing systems to make dielectric withstand tests of specified kind of isolation, so they are subject to different criterion of selection. Because of constructional limitations of high voltage test transformers following from maximal levels of test voltages, a type of test voltages (facial or interfacial) and maximal mechanical structural strength, there aren’t produce one type high voltage test transformers.

We can make following constructions for the sake of the way of location of windings on a core:

a) when a coil or primary coils (low voltage) and a secondary coil (high voltage) are on one column of magnetic core. The secondary coil is located on a coil or primary coils. The beginning of the secondary coil and an earth electrode of core are connected and taken out from transformer to ground (Fig. 1a). This type of high voltage test transformers is the most popular, because it’s easy to define their parameters and make them.

Fig. 1 Interior of high voltage test transformer with construction describing in a and b points.

b) when a coil or primary coils and a secondary coil are on the central column of jacket coat core. The secondary coil is located on a coil or primary coils. The beginning of the secondary coil and an earth electrode of core are connected and taken out from transformer to ground (Fig. 1b).

This solution is applied in mobile high voltage testing system, where transformer must be more mechanical resistant. This type of high voltage test transformer is marked by smaller leakage of magnetic flux than construction in point a.

c) when primary and secondary coil are split into half and located on two columns of magnetic core (Fig. 2). Coils are located in this way, that secondary coils are put on every primary coils. The beginning of the secondary coil and an earth electrode of core are taken out from transformer to ground. Primary coils are connected parallel, whereas secondary coils are connected in series. In this way we can receive half test voltage on every secondary coils. This construction is characterized by the smallest leakage of magnetic flux. Material consumption of winding is also smaller than it is in construction describing in a and b points. Unfortunately, the problem is assurance right level of primary isolation between both secondary coils, because the beginning and the end of coils, which are connected in series are located very near each other. The next problem is assurance right level of primary isolation between primary and secondary coils, because there is a half test voltage between them.

Fig. 2 Interior of high voltage test transformer with construction describing in point c.

d) when is only one primary winding and many secondary windings. A primary coil is put on column of plain-frame magnetic core, while secondary coils which are connected in series are put on a primary coil. This solution in high voltage test transformer is especially applied to receive test voltage on both poles displaced about 180 (Fig. 3).

Fig. 3 Interior of high voltage test transformer with construction describing in point d.

e) cascade, where binding coils are put on two columns of magnetic core. Secondary winding is put on binding coils. Primary winding or windings (law voltage) are put on a bottom secondary coil of first grade cascade. Coupling winding is put on a top secondary coil of second grade cascade in case of two or multicore cascade solution. Coupling coils are put on secondary coils in next grades of cascade. Because a core has potential of half primary voltage of every grades of cascade, so binding coils have to have the same potential as core. For this reason they are connected parallel with each other and in the same place as core. The end of bottom secondary coil and the beginning of top secondary coil are connected with each other and with core to have the same potential of core. The end of top secondary coil and the beginning of bottom secondary coil of next grade of cascade are connected with each other and connecting parallel windings (Fig. 4). High voltage test transformers with cascade construction are made when it’s impossible to make a high voltage test transformer with construction describing in point ‘a’ as regards dimensions or strength of primary isolation.

Fig. 4 Interior of step-up cascade with one core, two-stage transformer.

We can make following constructions for the sake of the way of making primary isolation:
a) with paper-oil primary isolation
b) with polypropylene foil and gas SF6 primary isolation
c) with resinous primary isolation
d) with silicon – estrofol foil primary isolation
e) with mix primary isolation

Selection of kind of isolation of high voltage test transformers is dependent on maximum closed-circuit voltage. The most often applied primary isolation is paper-oil isolation or polypropylene foil with gas S_F6. In narrow range of test voltage is applied resinous primary isolation or silicon – estrofol foil primary isolation. The way of making of primary isolation is dependent on closed-circuit voltage at which the high voltage test transformer is made. The higher the closed-circuit voltage of transformer the more complicated execution of primary isolation.

3.Design

When we design a new High voltage test transformer we must take note of its application in high voltage testing system, which determine the main construction parameters.

Depending on use in high voltage test transformers we can distinguish following parameters:
a) rated frequency
b) primary voltage
c) secondary voltage
d) secondary voltage with short-time rating
e) short-circuit voltage
f) voltage branch measure
g) voltage branch of high voltage
h) continuous power rating
i) short-time power rating
j) primary continuous rated current
k) primary short-time rated current

For example if high voltage testing system on output should have high sinusoidal variable voltage at power-line frequency and additionally possibility to install rectifier we can design a high voltage test transformer on power-line frequency 50Hz. But if high voltage testing system on output should have rectified voltage permanently it isn’t economical solution to design high voltage test transformer on power-line frequency 50Hz. In this situation it should be design on much higher frequency than power-line frequency.

If we take the duration of the high-voltage test in a laboratory into consideration it can turn out that design of high voltage test transformer on continuous power isn’t necessary and we can design it depending on the required maximum duration of test on short-time rating.

When we define the parameters on which the high voltage test transformer have to be design we can make calculations of

a) a core and windings
b) parameters of substitute diagram
c) voltage and angle errors

Some of the most common computational schemes of high voltage test transformers are represented in Fig. 5. The values appointed by figure 1 on computational schemes are related to primary side of high voltage test transformer (law voltage), while figure 2 are related to secondary side of high voltage test transformer (high voltage)

Fig. 5 The computational scheme of High Voltage Test Transformer a) with one primary winding; b) with two primary windings connecting in series; c) with two primary windings connecting parallel; d) with secondary winding with a branch of high voltage.

The way of making of calculation of parameters is very similar to calculations of parameters of single-phase instrument transformers [1]; [2] so it will not be described in the article. Voltage and angle errors in case of high voltage test transformers are necessary to redimensioning transformer voltage ratio. In this situation at full active or short-time fictitious load we can get maximum value of test voltage on which the transformer was designed. At errors it was been possible to define. The value of short-circuit voltage of transformer we can also calculate on the basis of errors.

The results of calculations and measurements of parameters of three high voltage test transformers analytically designed on basis of literature [1] and [2] are following.:

a) high voltage test transformers at continuous power 2kVA, supply voltage 230V, test voltage 25kV and frequency 50Hz
b) high voltage test transformers at continuous power 1,1kVA, supply voltage 260V, test voltage 41kV and frequency 50Hz
c) high voltage test transformers at continuous power 10kVA, supply voltage 250V, test voltage 100kV and frequency 50Hz

In the first stage of verification of analytic method were measured the resistances of windings of finished transformers. The results of calculate and measurement are in the Schedule 1.

Schedule 1. Windings resistance

The next steps was executed idle run and on her basis was calculated effective value current I_FE and passive value current I_μ no-load current I₀. The results of calculate and measurement are in the Schedule 2.

Schedule 2. Effective value I_Fe and passive value I_μ no-load value current I₀.

Large divergence of results for TP 1,1kVA and TP 10kVA can be connected with applied of steering screens, adjusting strengths of main isolation, which initiate additional capacity after side of winding of high voltage and also that in case of testing transformers with large voltage ratio, parallel and private windings capacity make up additional reactive load to transformer. It is hard to get idle run in case of high voltage transformers.

The next steps of verification of analytic results was been realization fault test to calculate short-circuit voltage and total reactance of both winding imported into primary side. Results for two testing transformers are in the Schedule 3.

Schedule 3. Value from fault test for two testing transformer.

4.Application

High voltage test transformers have following use:

a) in a complete high voltage testing systems to test of solid dielectric:
• high voltage indicator (high voltage testing systems in Fig. 7 and high voltage testing station in Fig. 6a)
• insulating stick (high voltage testing systems in Fig. 7 and high voltage testing station in Fig. 6b)
• rubber blanket (high voltage testing systems in Fig. 7 and high voltage testing station in Fig. 6c)

b) in high voltage testing systems to test of dielectric isolation in solid high voltage (Fig. 7b)
c) in testing device to test of dielectric isolation energetic cables by alternating or state high voltage (Fig. 8a)
d) in testing device to test of liquid dielectric isolation for example insulating oil (Fig. 8b)
e) in testing device to test dielectric isolation of dielectric gloves and dielectric shoes (Fig. 8c)

Fig. 6 High voltage testing station: a) to test high voltage indicator; b) to test insulating stick; c) to test rubber blanket

Fig. 7 High voltage testing systems to test dielectric isolation: a) alternating voltage with power line frequency; b) solid voltage

Fig. 8 Testing devices to test : a) of dielectric isolation energetic cables; b) of liquid dielectric isolation; c) of dielectric gloves and dielectric shoes

5.Conclusions

In this article were described the most frequently used constructions of high voltage test transformers. There were presented defects, advantages and limitations selected constructions of high voltage test transformers. In the article become specified parameters on which high voltage test transformer can be design with a reason of their choice. Analyzing results of prototypes of high voltage test transformers was verified correctness of computational method. Additionally comparison of results of calculations with results from measurements was used as a representation of problems which constructor encounters during design and checking of correctness of finished transformer. It is not easy to design the high voltage test transformers. Making allowance for economics factors, it is important to choose the cheapest construction of high voltage test transformer being on border of possibility of her realization. There are very important the parameters, which are characteristic for the construction because they can be essential for high voltage testing system. Knowledge of the construction of high voltage test transformers, their design and use in high voltage testing system gives the solution of the most adjustment transformer in respect of parameters and prices.

REFERENCES

[1] R. Nowicz, Voltage instrument transformers. Classic, special and unconventional Monographs of Technical University of Lodz, Lodz 2002. (in Polish)
[2] W. Starczakow, Instrument transformers, PWT, Warsaw 1959. (in Polish)
[3] E. Leśniewska, The Use of 3D Electric Field Analysis and the Analytical Approach for Improvement of a Combined Instrument Transformer Insulation System, IEEE Transactions on Magnetics, vol.38, no 2, March 2002, pp. 1233-1236
[4] E. Leśniewska, Improvement of the Electric Strength of an Insulation System of a Medium Voltage Instrument Transformer Using Field Analysis, Computer Engineering in Applied Electromagnetism, Springer 2005, Great Britain, pp.143-148
[5] Z. Flisowski, High voltage engineering, WNT, Warsaw 2009.
[6] J. Wodziński High voltage engineering of tests and measurements, PWN, Warsaw 1997

Author: mgr inż. Bogdan Tułodziecki, Fabryka aparatów elektrycznych Zwarpol Sp. z o. o. w Warszawie, ul. Żegańska 1, 04-713 Warszawa, e-mail: Bogdan.tulodziecki@zwarpol.com

Source & Publisher Item Identifier: PRZEGLĄD ELEKTROTECHNICZNY (Electrical Review), ISSN 0033-2097, R. 87 NR 1/2011

Nuisance Tripping of Sensitive Customer Power Electronic Equipment

Published by Electrotek Concepts, Inc., PQSoft Case Study: Nuisance Tripping of Sensitive Customer Power Electronic Equipment, Document ID: PQS1011, Date: October 15, 2010.

Abstract: This case study presents an investigation of nuisance tripping of sensitive customer power-electronic equipment during utility capacitor bank switching. The simulations for the analysis were completed using the PSCAD program. The power conditioning solutions included utility switches with pre-insertion resistors and customer series chokes. Both mitigation alternatives prevented the customer sensitive power- electronic equipment from tripping during the power quality events.

INTRODUCTION

A nuisance tripping of sensitive customer power-electronic equipment case study was completed for the system shown in Figure 1. The case study investigated the potential for tripping of customer power-electronic equipment during switching of a utility distribution capacitor bank. Several power conditioning mitigation alternatives, including utility switches with pre-insertion resistors and customer series reactors/chokes, were evaluated using computer simulations.

Figure 1 – Illustration of Oneline Diagram for Sensitive Equipment Evaluation

SIMULATION RESULTS

The simulations for the case study were completed using the PSCAD program. The accuracy of the simulation model was verified using three-phase and single-line-to-ground fault currents and other steady-state quantities, such as steady-state voltage rise. The circuit consisted of a 115 kV utility substation supplying a 30 MVA, 115 kV/13.2 kV step-down transformer. Three customers were also included in the simulation model to evaluate the effect of different types of power electronic loads. The customers included two 1,000 kVA, 13.2 kV/480 V step-down transformers supplying HVAC loads and one 100 kVA, 13.2 kV/415V step-down transformer supplying switch-mode power supply (SMPS) loads.

Utility capacitor bank switching is a normal system operation and the resulting transient voltages and currents are usually not a problem for utility equipment. However, there is a possibility that these low frequency transients can cause severe secondary transients if a customer has power factor capacitor banks or result in nuisance tripping of power electronic-based devices, such as adjustable-speed drives. Capacitor bank energizing is just one of the many switching events that can cause transients on a utility system. However, due to their regularity and impact on power system equipment, they quite often receive special consideration.

Power quality problems related to utility capacitor bank switching include customer equipment damage or failure, nuisance tripping of adjustable-speed drives or other process equipment, transient voltage surge suppressor failure, and computer network problems.

Energizing a shunt capacitor bank from a predominantly inductive source creates an oscillatory transient that can approach twice the normal system peak voltage (V_pk). The characteristic frequency (f_s) of this transient is given by the following expression:

where:
f_s = characteristic frequency (Hz)
L_s = positive sequence source inductance (H)
C = capacitance of bank (F)
f_system = system frequency (50 or 60 Hz)
X_s = positive sequence source impedance (Ω)
X_c = capacitive reactance of bank (Ω)
MVA_sc = three-phase short circuit capacity (MVA)
MVAr_3φ = three-phase capacitor bank rating (MVAr)
ΔV = steady-state voltage rise (per-unit)

The characteristic energizing frequency for the simulated 7,200 kVAr, 13.2 kV distribution capacitor bank with a source strength of about 320 MVA may be approximated using the following expression:

The steady-state voltage rise for this case may be approximated using the following expression:

Relating the characteristic frequency of the capacitor bank energizing transient (f_s) to a steady-state voltage rise (ΔV) design range provides a simple way of quickly determining the expected frequency range for utility capacitor bank switching. For example, a 60 Hz system with a design range of 1.0% to 2.5% would correspond to characteristic frequency range of 380 to 600 Hz. For a shunt capacitor bank on a utility bus, feeder/cable capacitance and other nearby capacitor banks cause the energizing transient to have more than one natural frequency. However, for the first order approximation, this equation can still be used to determine the dominant frequency.

Because capacitor voltage cannot change instantaneously (remembering that i(t)=Cdv/dt), energization of a capacitor bank results in an immediate drop in system voltage toward zero, followed by an oscillating transient voltage superimposed on the fundamental frequency waveform. The peak voltage magnitude depends on the instantaneous system voltage at the instant of energization and can approach twice the normal system voltage. For a practical capacitor bank energization without trapped charge, system losses, loads, and other system capacitances cause the transient magnitude to be less than the theoretical 2.0 per-unit. Typical magnitude levels range from 1.3 to 1.5 per-unit and typical transient frequencies generally fall in the range from 300 to 1000 Hz. Figure 2 illustrates an example measured distribution system capacitor bank energizing transient.

Figure 2 – Example of a Distribution Capacitor Bank Energizing Transient Voltage Waveform

Nuisance tripping refers to the undesired shutdown of a customer’s adjustable-speed drive or other power-electronic-based process device due to a transient overvoltage on the device’s dc bus. Very often, this overvoltage is caused by utility transmission or distribution capacitor bank energization. Considering the fact that many distribution banks are time clock controlled, it is easy to see how this event can occur on a regular basis, thereby causing numerous process interruptions for customers.

An adjustable-speed drive system consists of three basic components and a control system as illustrated in Figure 3. The rectifier converts the three-phase ac input to a dc voltage, and an inverter circuit utilizes the dc signal to produce a variable magnitude, variable frequency ac voltage, that is used to control the speed of an ac motor. A dc motor drive differs from this configuration in that the rectifier is used to control the motor directly.

The nuisance-tripping event consists of an overvoltage trip due to a dc bus overvoltage on voltage-source inverter drives (e.g., pulse-width modulated inverter). Typically, for the protection of the dc capacitor and inverter components, the dc bus voltage is monitored and the drive tripped when it exceeds a preset level. This level is typically around 780 V (for 480 V applications), which is only 120% of the nominal dc voltage. The potential for nuisance tripping is primarily dependent on the switched capacitor bank rating, overvoltage controls for the switched bank, the dc bus capacitor rating, and the inductance between the two capacitors. It is important to note that nuisance tripping can occur even if the customer does not have power factor correction capacitor banks.

Figure 3 – Illustration of Adjustable-Speed Drive Circuit Components

The initial simulation (Case 5a) involved the basecase condition of energizing the 7,200 kVAr, 13.2 kV distribution substation capacitor bank with no mitigation added on either the utility or customer systems. Figure 4 shows the resulting three-phase voltages at the 13.2 kV substation bus. The maximum transient overvoltage was 1.86 per-unit and the simulated steady-state voltage rise was 2.14%, which compares reasonably well with the calculated value of 2.25%.

Figure 5 shows the dc link voltages for the two customer HVAC adjustable-speed drives. The maximum dc link voltage was 912 V for the 10 hp drive with no choke and 760 V for the 15 hp drive with a 1.5% choke. The assumed trip level was 780 V. In addition, there were no utility or customer MOV arresters included in the model.

Figure 4 – Illustration of Substation Bus Voltage during Capacitor Bank Switching

Figure 5 – Illustration of HVAC dc Link Voltages during Capacitor Bank Switching

Figure 6 shows the ac current for the worst phase of the customer SMPS loads. The maximum ac current was approximately 62 A during the utility capacitor switching event. Excessive surge currents for secondary power supply loads may cause rectifier diodes, transistors, filter capacitors, MOVs, main fuses, and other components to fail.

Figure 6 – Illustration of SMPS ac Current during Capacitor Bank Switching

The most effective methods for eliminating nuisance tripping are to reduce the energizing transient overvoltage, or to isolate the drives from the power system with series inductors, often referred to as chokes. The additional series inductance of the choke will reduce the transient magnitude at the input to the drive and the associated current surge into the dc link filter capacitor, thereby limiting the dc overvoltage.

A capacitor bank switch with a pre-insertion resistance provides a means for reducing the transient currents and voltages associated with the energization of a shunt capacitor bank. The impedance is shorted-out (bypassed) shortly after the initial transient dissipates, thereby causing a second transient event. The insertion transient typically lasts for less than one cycle of the system frequency. The performance of pre-insertion impedance is evaluated using both the insertion and bypass transient magnitudes, as well as the capability to dissipate the energy associated with the event, and repeat the event on a regular basis. Pre-insertion resistors and high-loss pre-insertion inductors are one of the most effective means for controlling capacitor bank energizing transients. The optimum resistor value for controlling capacitor bank energizing transients depends primarily on the capacitor bank rating and the source strength. It should be approximately equal to the surge impedance formed by the capacitor bank and source.

The second simulation (Case 5b) involved an evaluation of the utility mitigation alternative of using a capacitor bank switch equipped with a pre-insertion resistor. A standard pre – insertion resistor rating of 6.4Ω was chosen for the simulation because it was commercially available for a 15 kV class capacitor bank switch.

Figure 7 shows the resulting three-phase voltages at the 13.2 kV substation bus. The maximum transient overvoltage was reduced from 1.86 per-unit to 1.20 per-unit with the pre-insertion resistor. Figure 8 shows the dc link voltages for the two customer HVAC adjustable-speed drives for the pre-insertion case. The maximum dc link voltage was 720 V for the 10 hp drive with no choke and 644 V for the 15 hp drive with a 1.5% choke. Therefore, it was assumed that neither customer adjustable-speed drive would trip for this case. Figure 9 shows the ac current for the worst phase of the customer SMPS loads. The maximum ac current was reduced from 62 A to 30 A for the pre-insertion resistor case.

A commonly applied customer mitigation alterative is an inductive choke, which provides additional impedance in a circuit in much the same manner that an isolation transformer does, but at a much-reduced cost. They are often applied to the front-end of adjustable- speed drives to protect the drives from nuisance tripping caused by capacitor bank switching and other normal power system switching operations. Some motor drives have been found to be sensitive to overvoltages as minor as 1.2 per-unit. Inductive chokes limit these overvoltages to below the trip setting of the drive. They are generally rated as a 3% impedance, based on the drive kilowatt (or hp) rating. Some drive manufacturers now produce drives with chokes as part of their standard design. Chokes also help prevent voltage notching, caused by power electronic switching, from disturbing other equipment. They can limit notching to the drive side of the inductive choke.

Figure 7 – Illustration of Substation Bus Voltage with a Pre-Insertion Resistor

Figure 8 – Illustration of HVAC dc Link Voltages with a Pre-Insertion Resistor

Figure 9 – Illustration of SMPS ac Current with a Pre-Insertion Resistor

The final two simulations (Case 5c and Case 5d) involved an evaluation of the customer mitigation alternative of two different choke ratings that were added to the 10 hp adjustable-speed drive. The inductance rating for a choke that is specified in %X and hp may be approximated using:

where:
f_system = system fundamental frequency (50 or 60 Hz)
X = inductive reactance of ac choke (%)
kV_φφ = system rms phase-to-phase voltage (kV)
hp = horsepower rating of the drive (hp)

Figure 10 shows the resulting simulated current waveforms highlighting the effect of adding a 3% choke to the 10 hp drive. The steady-state current distortion (I_THD) for the case with no additional choke was 77.8%. Adding a 1.5% choke reduced the current distortion to 45.9%, while adding a 3.0% choke reduced the current distortion to 36.8%. In addition, the 3% choke reduced the magnitude of the transient inrush current into the drive from approximately 344 A to 100 A.

Figure 10 – Illustration of HVAC dc Link Currents for Two Choke Ratings

Figure 11 shows the resulting dc link voltages for the customer 10 hp adjustable-speed drive for the various simulated choke ratings (Case 5a, Case 5c, and Case 5d). The maximum dc link voltage was 912 V for the 10 hp drive with no added choke. The maximum dc link voltage was reduced from 912 V to 760 V with a 1.5% choke and to 725 V with a 3.0% choke. Since the assumed trip level was 780 V, the customer drive did not trip after the addition of the either the 1.5% or 3.0% choke.

Figure 11 – Illustration of HVAC dc Link Voltages with Various Choke Ratings

SUMMARY

This case study investigated nuisance tripping of sensitive customer power-electronic equipment during utility capacitor bank switching. The power conditioning solutions that were evaluated included utility switches with pre-insertion resistors and customer series chokes. Both mitigation alternatives prevented the customer sensitive power-electronic equipment from tripping during the power quality events.

REFERENCES

1.IEEE Recommended Practice for Monitoring Electric Power Quality,” IEEE Std. 1159-1995, IEEE, October 1995, ISBN: 1-55937-549-3.

2.IEEE Recommended Practice for Emergency & Standby Power Systems for Industrial & Commercial Applications (IEEE Orange Book, Std. 446-1995), IEEE, ISBN: 1559375981.

3.R.C. Dugan, M.F. McGranaghan, S. Santoso, H.W. Beaty, “Electrical Power Systems Quality,” McGraw-Hill Companies, Inc., November 2002, ISBN 0-07-138622-X.

RELATED STANDARDS
IEEE Std. 1159, IEEE Std. 1100, IEEE Std. 446, ANSI Std. C84.1

GLOSSARY AND ACRONYMS
ASD: Adjustable-Speed Drive
CF: Crest Factor
DPF: Displacement Power Factor
PF: Power Factor
PWM: Pulse Width Modulation
THD: Total Harmonic Distortion
TPF: True Power Factor

Power Quality Monitoring Provides Additional Value

Published by Mark Wojdan, P.E., Date: Aug. 23, 2018.

Hydro Ottawa’s central power quality program improves asset reliability while generally lowering operating and maintenance expenses.

Many utilities have experienced how labor intensive it is to retrieve and compare power quality (PQ) data from numerous devices and systems, no matter the infrastructure in place. Delays and inefficiencies in data analysis impede the early detection and investigation of electricity system faults. In turn, these failures in productivity and performance gaps increase the risk of costly repairs, major asset replacements and prolonged network outages.

To mitigate these issues, the revenue metering program in Canada’s National Capital Region was expanded to include PQ monitoring in 2002. As a recently amalgamated utility with more than 300,000 residential and commercial customers in a service territory of 1116 sq km (431 sq miles), Hydro Ottawa Ltd. began to record long-term statistics on voltage sags and harmonic distortion at key distribution substations.

PQ Monitoring

In 2004, Hydro Ottawa installed PQView, a proprietary central PQ monitoring and analysis system. PQView integrates PQ-related disturbance and steady-state measurement data, site characteristics and event information generated from multiple monitors, relays, recorders and other instruments. Equipped with automated analytical and reporting tools, the system has been instrumental in helping Hydro Ottawa to better understand, predict and respond to all electricity events occurring on the distribution network.

Image: T&DWorld (tdworld.com) – Fig.1. Damaged Tap Changer

Over a period of 10 years, Hydro Ottawa expanded its PQ system to more than 125 monitoring locations, including all 8.3-kV, 13.2-kV, 27.6-kV and 44-kV substation bus bars. Measuring bus voltage and current, these PQ monitors are installed on the secondary side of the substation transformer.

Most of the data is downloaded from the monitors to PQView using broadband communications (Ethernet) through the corporate network. Although some data is still being downloaded by modem, the PQ monitors remain accessible to other computers at Hydro Ottawa through fiber-optic wide-area-network connections.

Fault Location

Image: T&DWorld (tdworld.com) – Fig.2. Fault Event Waveforms

In 2014, PQView was augmented with FaultPoint, an automatic fault location system (AFLS) module that identifies fault causes, problem conditions and fault locations with greater accuracy. Email notifications are issued by the control center, which — together with the estimated fault location maps that are available online within five minutes — enables Hydro Ottawa’s field crews to identify the fault location and repair equipment more quickly than previously possible.

The AFLS module incorporates the use of measurements from PQ monitors, distribution circuit models, SCADA operations, and Hydro Ottawa’s geographic information system (GIS). Measurements recorded at the distribution substations are downloaded automatically and incorporated into PQView. These measurements are then used to calculate the circuit reactance from the distribution substation to the fault. The calculations are based on phasor measurements derived from the voltage and current values. They also include calibration constants based on previous fault measurements and known locations.

The result of these calculations is an estimated reactance to fault (XTF). The XTF values are compared to line models that estimate the positive-sequence and zero-sequence reactance between the distribution substation and circuit structures. The calculated fault locations then can be viewed using PQView’s web application (PQWeb), enabling the estimated locations to be displayed on single-line circuit diagrams overlaid on Esri or Microsoft maps.

Most of the distribution substations on Hydro Ottawa’s distribution network are designed with four medium-voltage bus bars, each supplying four medium-voltage feeders. The bus bar voltage and current from each distribution transformer are monitored by a single Schneider Electric ION PQ and revenue meter.

Measurements by the PQ monitors are triggered using high and low root-mean-square (rms) voltage thresholds. When a voltage sag is detected (less than 90% of nominal voltage) or voltage swell is detected (more than 110% of nominal voltage), the monitor is triggered to record samples of the voltage and current waveforms, including the rms.

These measurements are downloaded by PQView and passed through a fault characterizer, which looks for the signatures of permanent faults, incipient sub-cycle faults, magnetizing transformer inrush currents, phase imbalance and more. If a measurement shows a fault lasting more than one cycle (longer than 16.677 msec), then the estimated reactance values to the fault are derived from its waveform samples.

Hydro Ottawa’s PQ monitors are configured to record voltage and current waveform samples at a rate of 128 points per 60-Hz cycle, with typically five cycles of pre-trigger and 10 or more cycles of post-trigger data. The PQ monitors communicate with a server through a broadband Ethernet connection, so the fault measurements can be downloaded from the monitors to PQView within minutes.

Storing Circuit Models

Image: T&DWorld (tdworld.com) – Fig.3. Outdoor ION Meter Cabinet

The distribution network circuit models are stored in Eaton Industries CYMDIST databases, which are extracted from Hydro Ottawa’s GIS. These models provide the geospatial coordinates for the nodes that comprise the line segments of medium-voltage distribution feeders in a Lambert conformal conic projection system. The coordinates are converted to the World Geodetic System (WGS84) so maps can be displayed as overlays in standard GIS software systems.

The circuit models include the underground cable and overhead line conductor characteristics used in different circuit sections. They also include positive-sequence and zero-sequence impedance characteristics. The number of phases for each circuit section is stored as well as whether the medium-voltage feeder is an underground cable or overhead line conductor. In addition, the cumulative impedance for each underground cable and overhead line conductor section of each medium-voltage circuit is stored in the PQView database.

Integrating Data

Image: T&DWorld (tdworld.com) – Fig.4. FaultPoint

Once the data is downloaded from the distribution substation, it only takes a few minutes for the waveforms and other data from the PQ monitors to be integrated automatically into PQView. The measurements can be queried from the PQView database and analyzed directly using workstation computer applications or indirectly through intranet web applications. For example, analysis of voltage characteristics and zero-sequence current characteristics may indicate a single-phase fault has occurred. Other line voltage characteristics can be examined that indicate a two-phase or three-phase fault has occurred. Harmonic content, waveform shape and event duration also are used to identify events, such as magnetizing current inrush events. Zero-sequence and negative-sequence current content is used to search for other overcurrent events that are not faults but otherwise noteworthy for automatic notification.

A single measurement may be classified as more than one type of fault. This means FaultPoint can identify single-phase faults that evolve into multiphase faults. For example, the system can identify the start and end of each stage of a fault that begins as a transformer energizing transient but degrades into a fault condition.

On the Hydro Ottawa intranet, several applications also can provide system operators and engineering teams with estimated fault locations, including the use of satellite imagery. Multiple estimated locations also are possible whenever a feeder is interconnected or has multiple branch paths.

Fault Circuit Indicators

Image: T&DWorld (tdworld.com) – Fig.5. FaultPoint Map

As part of Hydro Ottawa’s network modernization, fault circuit indicators (FCIs) have been installed and polled by its SCADA system. The status of each FCI is stored in an OSIsoft PI System, which serves the role of SCADA historian.

As each fault measurement is downloaded, imported and identified, a query on the historian system is completed to determine if any circuit breaker positions or FCIs have changed status. If a status change is correlated with the fault recording, then there is more information to help pinpoint which feeder and feeder branch is the most likely location to have experienced the fault outage.

Distribution network operators use the estimated location of faults along with FCI data to assist in the interpretation of events that can occur on the network. This enables a prompt response in the mobilization of fault repair field crews to restore supplies quickly.

Early Detection

Since 2010, Hydro Ottawa has experienced six onload tap-changer failures on its power transformers. In all cases, final catastrophic failure of these tap-changers, and potentially the transformer, was averted through the detection of early equipment failure in PQView.

Although zero-current disturbances and high distortions in voltage and current waveforms were observed in some cases, Hydro Ottawa discovered voltage flicker was the predominant parameter used to predict tap-changer failures.

For enhanced vigilance to protect against this form of catastrophic failure, Hydro Ottawa plans to augment PQView with automatic microprocessor relay integration, outage management system integration and automated reporting for the International Electrotechnical Commission (IEC) and IEEE standards compliance.

Central PQ System Benefits

For Hydro Ottawa and other users of full-time PQ monitoring solutions, the ability to import time-sensitive power monitoring data from many sources and have it readily available in a central PQ monitoring and analytics system offers the following benefits:

• Protection for valuable assets. Finding and identifying the source of anomalies as quickly as possible provides a valuable insight in the understanding of, and response to, events on the distribution network. Well-integrated tools and systems can detect the imminent failure of capital intensive transformers, tap-changers and capacitor banks, enabling them to be taken out of service and repaired prior to catastrophic failure.

• Reduced outages and downtime. Eliminating the catastrophic failure of major components can reduce the number and frequency of outages. Timely access to event data can help the utility to pinpoint the location of faults quickly, reduce the time it takes to troubleshoot outages and improve restoration times.

• Optimized predictive maintenance. Being able to detect and investigate problems within minutes not only prevents damage but also reduces asset wear and tear as well as extends asset life cycles.

• Robust compliance. Monitoring PQ indices will enable both customers and energy providers to measure performance against industry standards, such as IEEE, IEC and CSA, and determine if remedial action is required.

• Ongoing customer service improvements. Full-time monitoring will capture most electrical events that can impact a customer’s supply. This enables system operators to respond swiftly by isolating the tap-changers from service.

• Electrical system awareness. Engineers and others will be more informed about events impacting customers, thereby reducing the time and resources required to improve service and reliability.

Summary

The proper integration of multiple databases and tools is key to a fully optimized, full-time power monitoring solution. It empowers utilities, generators and large users with better protection and control over the entire distribution network. The AFLS has proven to be dependable, resulting in improved asset reliability. The system has demonstrated tremendous value, being of benefit to the utility, especially when dealing with underground cable faults in busy city streets.

As system operators and operations engineers become more familiar with the AFLS, Hydro Ottawa can expect significant benefits. One benefit is a reduction in the time it takes to locate and repair faults, resulting in fewer operating and maintenance expenses. Another benefit is a reduction in outage duration, thereby reducing the customer average interruption frequency index.

Acknowledgement

The authors of this article wish to thank Gary Macleod of CPS – Current Power Services for all his support and the technical information he provided in the preparation of this article.

Authors

Mark Wojdan (markwojdan@hydroottawa.com), P.E., is supervisor of engineering programs and major projects at Hydro Ottawa Ltd. His responsibilities have included implementing maintenance programs for the distribution system, capacity planning and running the distribution system through best practices in asset management. He holds BSEE and MSEE degrees from the University of Waterloo, Canada.

Daniel Sabin (dsabin@electrotek.com) is a principal engineer with Electrotek Concepts Inc. and a software architect for the PQView and FaultPoint software systems. He was Hydro Ottawa’s consultant for this project. Previously, he was a project manager and research engineer with the Electric Power Research Institute. Sabin holds a BSEE degree from Worcester Polytechnic Institute and a MSEE degree from Rensselaer Polytechnic Institute. He is a registered professional engineer, an IEEE Fellow, and the current chair of the Transmission & Distribution Committee of the IEEE Power & Energy Society.

Sidebar

Hydro Ottawa

Hydro Ottawa is the third largest distribution utility in Ontario, Canada, responsible for distributing electricity to customers in the city of Ottawa and the village of Casselman. The customer class is primarily residential and commercial, with some industrial load.

Image: T&DWorld (tdworld.com) – Sidebar Table

The utility has invested in smart grid devices, including automated reclosers, automated pad-mounted sectionalizers, automated switchgear, supervisory control and data acquisition, fault circuit indicators, smart residential metering, and integrated revenue and power quality monitors.

Source URL: https://www.tdworld.com/grid-innovations/asset-management-service/article/20971579/power-quality-monitoring-provides-additional-value

Hybrid Power System of Public Lighting in Smaller Villages

Published by Stanislav MIŠÁK, Jaroslav ŠNOBL, František DOSTÁL, Daniel DIVIŠ,
VSB – Technical University of Ostrava

Abstract. This article deals with the possibility of public lighting power from renewable resources, it means of a hybrid system consisting of solar panels and wind power. The factual data for dimensioning the system was obtainedby extensive exploration of the state and consumption of public lighting in the villages of the Czech Republic. The article contains an economic reasoning and analysis of investment costs compared to cable distribution.

Streszczenie. Artykuł ten traktuje o możliwościach zasilania oświetlenia publicznego z odnawialnych źródeł energii, czyli systemu hybrydowego skladającego się z paneli słonecznych i elektrowni wiatrowej. Szczegółowe dane użyte do wszelkich wyliczeń uzyskano na podstawie szerokich badań dotyczączch stanu i zużycia energii przez oświetlenie publiczne w gmianch Republiki Czeskiej. Artykuł zawiera w sobe także uwagę ekonomiczną i analizę wydatków inwestycyjnych w porównaniu z siecią kablową. (Hybrydowy system zasilania oświetlenia publicznego w mniejszych gminach).

Keywords: public lighting, solar power station, wind power station, hybrid power source, energy balance.
Słowa kluczowe: oświetlenie publiczne, elektrownia słoneczna, elektyrownia wiatrowa, system hybrydowy, bilans energetyczny.

Introduction

During the realization of the SGS Project SP/201073 we have solved this year on the VSB-TU Ostrava, we implement a hybrid system using renewable energy sources (solar and wind power). These resources are applied to households with a defined power consumption. System consists of wind energy power 12kW and solar panels with capacity about 2kWp. Batteries are charging by the photovoltaic panels through the regulator.

Output of wind power is through the converter rectified into batteries, from which is continuously supplied simulated household during the time, according to its consumption. Based on this concept, we will try to apply the power of public lighting (hereafter PL) in small villages. The purpose is to modify the system so that can supply electricity public lighting in small villages or remote areas without power.

Statistical data on consumption

The data about electrical energy consumed by public lighting were obtained by extensive exploration, in which were subpoenaed cities and towns of the Czech Republic with a query about consumption in their city. The date we received was statistically processed and evaluated and results for small and medium-sized villages are listed in Table 1. Details of which we will determine are the installed power of one light point (hereafter SM) and the average number of lighting points per hundred inhabitants.

Fig.1. The concept of the proposed hybrid power system for public lighting

Table 1. Statistical data on electricity consumption of public lighting for small and medium-sized villages

Of the values listed in Table 1. is expressed the average number of lighting points and the average installed power for public lighting. In Table 2. is then calculated the average installed power of village public lighting. For the smallest intended village is power 6,63 kW, and this value will be dimensioned to hybrid system.

Table 2. Calculated data for public lighting

Table 3. Parameters and the price of a hybrid system

Proposal of a hybrid system to power public lighting the village

For using this system year round it must be designed to operate in winter months when the public lighting consumes electricity 16 hours a day. With regard to the possible realization and investment costs are for the calculation considered villages in which there lives 500 inhabitants or less. For this category of villages, the average installed power on light point is 78W, as we count 85 light points. So we obtain the installed power of public village lighting 6,63 kW. Power take-off from the rechargeable battery is designed for two nights during the winter without any charge from one or other renewable sources. The consumption for these two nights is 212kWh. During the summer demands for electricity are lower indeed, we consider the operation time only eight hours and a half consumption.

This system is used for illustrating the price costs of this kind of prototype and has function to explore whether is preferable to use a cable connection from the remote grid or need to build such a local island hybrid system. In both cases we expect that public lighting is newly built or will complete its reconstruction. The price of public lighting is not considered. Further there is the calculation and mutual comparation with a variant of remote connection and consumption of electrical energy to power 20 years, a life time of our hybrid system.

For making an idea there are compared different lengths of power connections with price of a hybrid system. The following table shows that the hybrid system is repayable under the conditions where the length of the power supply cable connections exceed 4 kms. The calculation considers a standard rates of electricity for public lighting for the year 2010, which are fixed during all 20 years.

Table 4. Parameters and prices of electrical supply

Table 5. Prices of electrical connections for various distances

Conclusion

This article shows theoretical possibility of solution of a separate power supply system for public lighting. Compares two different ways to power the locality and supply it by electrical energy. It demonstrate rough estimate of the cost for construction of electrical supply and costs of building the island hybrid system. The result shows that if the connection length exceeds 4 kms, the investment costs of these projects are equal. But if we take the life of the hybrid system maximum 20 years and the life of cable connection maximum 40 years then we have to submit that building connection with a length of 4 kms is much better from the economic point of view. For connections with a distance longer than 8 kms is preferable to install a hybrid system of the island power system. This application can be used especially for inaccessible areas with such a terrain, which would be considerably more expensive excavation works with regard to soil type and very remote areas, it means remote parkings and highway rest areas, a mountain cottages, villages or farms.

Acknowledgement

This article was created under project SP/201073, “Využití hybridních obnovitelných zdrojů elektrické energie”

REFERENCES

[1] Mišák, S., Prokop, L.: Analýza technických a ekonomických parametrů hybridních systémů. In 11th International Scientific Conference Electric Power Engineering 2010; (EPE 2010), 2010.
[2] Novák T., Mišák S., Sokanský, K.: Využití obnovitelných zdrojů energie k napájení svítidel veřejného osvětlení. In 11th International Scientific Conference Electric Power Engineering 2010; (EPE 2010), 2010.

Authors: VŠB-TU Ostrava, Fakulta elektrotechniky a informatiky, katedra Elektroenergetiky, 17.listopadu 15, 708 33, Ostrava-Poruba, http://www.fei.vsb.cz;
doc.Ing. Mišák Stanislav, Ph.D., tel: 597329308, E-mail: stanislav.misak@vsb.cz
Ing. Šnobl Jaroslav, tel: 597329309, E-mail: jaroslav.snobl@vsb.cz
Ing. Dostál František, tel: 597324198, E-mail: frantisek.dostal@vsb.cz
Ing. Diviš Daniel, tel: 597323468, E-mail: daniel.divis@vsb.cz.

Source & Publisher Item Identifier: PRZEGLĄD ELEKTROTECHNICZNY (Electrical Review), ISSN 0033-2097, R. 87 NR 4/2011

Impact of Protective Relays on Voltage Sag Index

Published by Xinke GAO¹,² , Yapeng LIU³ , Congying WANG⁴,
School of Electronic, Information and Electrical Engineering, Shanghai Jiao Tong University (1),
Institute of Information Technology Luoyang Normal College (2),
Power Supply of Qingdao Company, Shandong Electric Power Corporation (3),
School of foreign language, Shanghai Jiao Tong University (4)

Abstract. This paper provides the probability-assessment analysis on the characteristic value of the voltage sag by using Monte Carlo stochastic modelling method to stimulate the randomness of the short circuit fault. Furthermore, this article simulates the influence of the protection devices on the voltage sag to ensure the authenticity and the referential reliability. A system with inverse-time protection devices equipped on each lines which could coordinate together are designed to cut off the short-circuit fault. The voltage sag of the designed system is evaluated by the pre-and post system average RMS variation frequency index, and the voltage sag index is compared with the ITIC curves. The simulation results demonstrated that the inverse-curve relay protection equipments are well-coordinated, and the severity and the range of the voltage sag are influenced by the cooperation of the equipped inverse time protection devices.

Streszczenie. W artykule przedstawiono metodę szacowania prawdopodobieństwa wystąpienia zapadu napięcia na podstawie analizy jego charakterystycznych parametrów zamodelowanych metodą Monte Carlo. Ponad to, w celu weryfikacji skuteczności, dokonano symulacji wpływu urządzeń ochronnych na zapady napięcia. Zaprojektowano także system z urządzeniami umożliwiającymi odizolowanie zwarcia w obwodzie od reszty sieci. Wyznaczono współczynnik częstotliwościowy zmienności wartości średniej RMS zapadów napięcia w proponowanym układzie, który następnie porównano z krzywymi ITIC. Przeprowadzone badania symulacyjne potwierdziły skuteczność i szybkość działania systemu. (Wpływ przekaźników ochronnych na współczynnik zapadu napięcia).

Keywords: Voltage sag, Protective relay, Monte Carlo algorithm, simulation.
Słowa kluczowe: zapad napięcia, przekaźnik ochronny, algorytm Monte Carlo, symulacja.

1.Introduction

Owing to the rapid technology proliferation in industrial control processes, as well as the large implementation of sophisticated electrical apparatus, the high power quality is required by manufacturing factories and commercial electrical consumers. The major power quality problems that interested industries are the voltage sag and swell. The existence of voltage sag can cause damaged product, lost production, restarting expenses and danger of breakdown, but voltage swells can cause over heating tripping or even destruction of industrial equipment such as motor drives [1]. Nowadays, most of the equipments used in the industries are mainly based on semiconductor devices and microprocessors and hence these devices are very sensitive to voltage disturbances. Among power disturbances, voltage sags are considered as the most frequent types of disturbances in the field and their impacts on sensitive loads are severe. Voltage sags have attracted many researchers to perform assessment and mitigation related to such power quality disturbances [2].

The current statistical methods to analyse the influence of voltage sag can be divided into stochastic prediction and electromagnetic transient analysis. For the stochastic prediction there are the fault location and the critical distance methods, paper [3] gives a brief comparison: the critical distance method is more suitable for manual project calculation of lower computational accuracy; The fault location method is more precise for programming, and this method can assure a more precise result with enough fault locations. But for both the fault location and the critical distance method, the fault occurrences are manually set, without considering the randomness of the locations and the types of actual faults, the papers [4-9] use the Monte Carlo algorithm and the electromagnetic transient analysis, only taking the definite time delay protection equipment influence into consideration.

At the moment both the mid voltage and low distributive networks apply the three sectional over-current protections, whose shortcomings are that these will generate the unnecessary loss to ensure the selectivity needed to cut down the fault. Nevertheless the inverse-time protection referred in papers [10-18] hold the advantages of self-adaptive functions and less affected by the way of operation. With the development of the digital protection technology, CIGRE and IEEE both establish the standards for the time-inverse relay protection, which are being applied in national low-voltage distributive networks step by step.

To sum up, this paper uses the method which combines the electromagnetic transient simulation and Monte Carlo methods to analyze the low-voltage distributive networks with the inverse-time protection relays installed. This article mainly discusses the influence of the inverse-time protection relays including designing protection relays which effectively coordinate together to cut off the short-circuit fault, and gives an analysis based on the voltage sag criteria such as SARFI (System Average RMS Variation Frequency Index) parameter and ITIC curve. These analysis results could be used for the further studying the impacts of the protective devices for the voltage sag.

2.Setting coordination of inverse-time over-current relays

2.1. Introduction of inverse-time relay

For the moment, there are two criteria for inverse-time relays, which are IEC255-03 [11] and IEEE STD C37.112-1996 [12] with their time-current equations as follows.

Referring to IEC255-03(1989-05) the inverse-time standard formulas are classified into three kinds： inverse, very inverse, and extremely inverse:

INVERSE (FSXTX=1.0):
(1) t = 0.14 x TDS / ((I / I_pu)^0.02 -1)

VERY INVERSE (FSXTX=2.0):
(2) t = 13.5 x TDS / ((I / I_pu) -1)

EXTREMELY INVERSE (FSXTX=3.0):
(3) t = 80 x TDS / ((I / I_pu)² -1)

where I is the current value going into relays, t is time to trigger, TDS is a factor to distinguish each member of a family, I_puis the pickup current (the smallest value that will trigger the breaker).

Referring to IEEE Std C37.112-1996 the standard formula representing type CO and IAC relays, considering overtravel and resetting characteristics and the relay coordination are as follows:

(4) t_trip(I) = TDS(A / (M^P +1) +B) +K

(5) t_reset(I) = TDS(t_p / (1-M^q))

Where t_tripis the operating time to trip in seconds, t_reset is the operating time to reset in seconds. M is the multiple of pickup current, M = I / I_pu. TDS is time dial operation, and p and q are exponent constant to stand for various characteristics.

2.2. Design of inverse-time relay

The simulation module in this paper is designed as the low-voltage distributive network with the arc-suppression coils. When the power system is under the normal operation, there is no current flowing through the arc-suppression coils. While the network is under the thunder attack or single phase short circuit, the voltage at the neutral point reaches to the value as large as the phase voltage. At the same time, the inductive current which flows through the arc-suppression coils and the capacitive fault current caused by the single phase-to-earth fault are compensated with each other to small amount of residual current. The residual current is not so large enough that cause the arc to extinguish without arousing the overvoltage. The lower fault current makes the longer delay for the inverse-time relay protection operation.

The inverse-time protection relay equipment applies the module built-in PSCAD, and the parameter design is based on extreme inverse-time parameter designed as the following equation by the IEEE Std C37.112-1996 thoroughly explained in paper [12], using very inverse-time standard without considering resetting characteristics here.

(6) t_trip(I) = TDS(3.922 / (M^0.02 +1) +0.098) +K

Take example of the simulation analysis of the fault occurred triply. The single phase-to-earth needs the longest time delay for operating the inverse-time relay protection equipments. The theoretical delay time could be got according to the time-current curve in the inverse-time relay module designed in PSCAD.

The PSCAD functions in terms of time sequence, the actual tripping moment ( T_r ) lags behind the theoretical time ( T_t ) at the same current peak ( I_p ). The beginning time and the ending time are put in T_start and T_end . All these parameters are shown in table 1.

The table 1 and the Fig.1 and Fig.2 prove the excellent cooperations and operations among the inverse-time modules. All the seven lines are equipped with inverse-time relay protection, and the voltage-sag characteristics variations are to be explained later.

Table 1. Protective devices acting time table

Fig. 1. Fault occurrence current graph with successful reclosing

Fig. 2. Fault occurrence voltage graph with successful reclosing

3.Simulation analysis considering inverse-time relays

3.1. Introduction of the simulation model

The simulation system structure and the parameter are explained as follows: the voltage grade with 110/25/0.4 kV, Y_n / Y_n wiring in transformer T₁ with a voltage ratio 110/10.5kV; the transformer T₂ 、T₃ 、T₄ 、T₅ all configured as Δ – Y₀ wiring with a voltage ratio in 25/0.4kV. As shown in Fig.3, the system is of seven lines all with the inverse-time relay protection equipments owning the same characteristic curves, and they are respectively the L₁ ~ L₃ of 500m length, L₄ ~ L₇ of 250m length.

Fig. 3. System simulation module

3.2. Probabilities assessment for the simulation results

3.2.1 Assessment based on the ITIC curve

The ITIC curve shown in Fig.4 based on large amount of experiment data features the equipment endurance capability standard developed from the CBEMA curve describing the vulnerability level of the information industry equipments to the transient power quality (mainly the voltage sag, rise, short interruption). The curve currently recognized as IEEE446 standard to evaluate the influence of the transient power disturbances explains the capability for the loads to bear the voltage sag.

• Without relay protective devices
In order to summarize the characteristics of the single phase-to-earth fault, take the A phase as an example shown in the Fig.5 and Fig.6.

As the results shown in Fig.5 and Fig.6, the influence of the transformer Δ – Y that the fault voltage caused by the single phase-to-ground transformed from the TB₁ type to the normal type as the N type leads to the significantly lowered dangerous voltage sags at the LV side with excessive voltage conditions disappearing;

According to the historical statistical data, the percentage of the single phase-to-earth is 75%, i.e. the excessive voltage is 75%. Hence the excessive voltage on medium voltage of the B and the C phases caused by the single phase-to-earth fault holds the highest occurrence probability.

• With relay protective devices

Here presents the simulation results considering the protection configuration between circuit breaker using the time-inverse characteristics and reclosers (with 100ms reclosing interval) with different mean fault time duration at 100ms, 600ms and 1s.

From Fig.7 and Fig.8, the trips whose numbers are almost the same with one of the interruptions do not intensively increase because most trips are on the faulted feeder generated from interruptions caused by three-phase faults.

Fig .7. Voltage sag and ITIC curve-mean fault duration=100ms

Fig.8. Voltage sag and ITIC curve-mean fault duration=600ms

Fig.9. Voltage sag and ITIC curve-mean fault duration=1000ms

According to Fig.8, compared with Fig.9, the protective devices work more precisely as the fault duration gets enough longer because the value of the short circuit current is lower with the arc-suppression coils equipped. With shorter mean fault duration time, most interruptions caused by three-phase faults rather than single-phase ones will cause an equipment trip only to loads located on the faulted feeder while with longer mean time duration most trips will be caused by single-phase faults.

3.2.2 Calculation based on the SARFI index

The characteristic measures for the voltage sag are the RMS offset and the voltage sag duration time, hence the most common index is the SARFI (System Average RMS Variation Frequency Index). One of the two common forms is the statistic index number—SARFIx used to explain a specific threshold voltage x which is meant to get the probability of the voltage RMS below the voltage threshold x. For a certain node the SARFIx could be calculated by the following expression:

The SARFIx of the whole system could be obtained by the following expression:

Where N_i is the number of customers whose voltage RMS under threshold voltage; N_T is the number of the entire assessed customer; n_n is the number of nodes in the whole system; N_j is the number of the customers belonging to the node; and SARFI_(j) is the SARFI value of the specific node.

Calculate all the values of SARFI1.1_MV, SARFI0.9_MV, SARFI0.8_LV, SARFI0.6_LV (SARFI1.1_MV means the RMS is over 110%). The results of SARFI refer to table 2. The longer duration time makes the SARFI1.1_MV value lower because it generates more chances for the protective devices to trip when the single-phase-to-ground fault happens in the system with the arc-suppression coils equipped. For the LV-level side, the lowest SARFI values with a threshold voltage below 90% are achieved when protective devices reject to operate, because most of the voltage sags generated by single-phase-to-ground faults are higher than the nominal voltage by 60%.

Table 2. SARFI calculation results

4.Conclusion

The comparison and contrast between the ITIC curve and the voltage sag index before and after the protective devices equipped show that the longer the fault duration lasts, the higher probability for the protective devices to operate, the more times for the loads on the low voltage to trip, i.e. the longer time for the sensitive loads to shut down. Therefore, the extent of the voltage sag become more severe, the main reason of which is the longer time demand for the protective devices to operate when single phase-to-ground fault happens in the arc-suppression coils grounding mode.

Here only presents the configuration of reclosers and circuits breakers. Further studies are expected to be analysed with other protective devices (e.g. fuses and sectionalizers) added and other reclosing cooperating patterns.

5. Acknowledgements

This work was supported by the Shanghai Jiao Tong University Innovation Fund for Postgraduates under Grant No.AE030202, Henan Tackle Key Problem of Science and Technology under Grant No.102102210454, the Foundation of Education Committee of Henan Province under Grant No.2011B520028, the Cultivated Funded Project of Luoyang Normal College under Grant No.10000859.

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[3] Won D.J., Ahn S.J.,Moon S.I., A modified sag characterization using voltage tolerance curve for power quality diagnosis, IEEE Trans. On Power Delivery, 20(2005), No. 4, 2638-2643.
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[5] Yunting S., Yongji G.,Ruihua Z., Probabilistic Assessment of Voltage Sags and Momentary Interruption Based on MONTECARLO Simulation, Automation of Electric Power Systems, 27(2003), No. 18, 47-51.
[6] Martinez J.A.,Martin-Arnedo J., Voltage sag analysis using an electromagnetic transients program, in Power Engineering Society Winter Meeting,(2002). 1135-1140.
[7] Martinez J.A.,Martin-Arnedo J., Voltage sag studies in distribution Networks-part I: system modeling, IEEE Trans. On Power Delivery, 21(2006), No. 3, 1670-1678.
[8] Martinez J.A.,Martin-Arnedo J., Voltage sag studies in distribution networks-part II: voltage sag assessment, IEEE Trans. On Power Delivery, 21(2006), No. 3, 1679-1688.
[9] Martinez J.A.,Martin-Arnedo J., Voltage sag studies in distribution Networks-part III: Voltage sag index calculation, IEEE Trans. On Power Delivery, 21(2006), No. 3, 1689-1697.
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Authors: Xinke GAO, Ph.D.Candidate of Department of Instrument Science and Engineering, School of Electronic, Information and Electrical Engineering, Shanghai Jiao Tong University, No. 800 of Dongchuan Road, Minhang District, Shanghai, CHINA. He is also an associate Professor of Institute of Information Technology, Luoyang Normal College,CHINA. gxk622@163.com

Source & Publisher Item Identifier: PRZEGLĄD ELEKTROTECHNICZNY, ISSN 0033-2097, R. 89 NR 5/2013

General Reference – Utility Capacitor Switching – Common Waveforms

Published by Electrotek Concepts, Inc., PQSoft Case Study: General Reference – Utility Capacitor Switching – Common Waveforms, Document ID: PQS0707, Date: January 1, 2007.

Abstract: The application of utility capacitor banks has long been accepted as a necessary step in the efficient design of utility power systems. Also, capacitor switching is generally considered a normal operation for a utility system and the transients associated with these operations are generally not a problem for utility equipment. These low frequency transients, however, can be magnified in a customer facility (if the customer has low voltage power factor correction capacitors) or result in nuisance tripping of power electronic based devices, such as adjustable-speed drives.

Capacitor energizing is just one of the many switching events that can cause transients on a utility system. However, due to their regularity and impact on power system equipment, they quite often receive special consideration.

INTRODUCTION

The application of utility capacitor banks has long been accepted as a necessary step in the efficient design of utility power systems. Also, capacitor switching is generally considered a normal operation for a utility system and the transients associated with these operations are generally not a problem for utility equipment. These low frequency transients, however, can be magnified in a customer facility (if the customer has low voltage power factor correction capacitors) or result in nuisance tripping of power electronic based devices, such as adjustable-speed drives (ASDs). Capacitor energizing is just one of the many switching events that can cause transients on a utility system. However, due to their regularity and impact on power system equipment, they quite often receive special consideration.

Transient overvoltages and overcurrents related to capacitor switching are classified by peak magnitude, frequency, and duration. These parameters are useful indices for evaluating potential impacts of these transients on power system equipment. The absolute peak voltage, which is dependent on the transient magnitude and the point on the fundamental frequency voltage waveform at which the event occurs, is important for dielectric breakdown evaluation. Some equipment and types of insulation, however, may also be sensitive to rates of change in voltage or current. The transient frequency, combined with the peak magnitude, can be used to estimate the rate of change.

There are a number of transient related concerns that are generally evaluated when transmission and distribution shunt capacitor banks are applied to the power system. These concerns include insulation withstand levels, switchgear ratings and capabilities, energy duties of protective devices, and system harmonic considerations. In addition, these considerations need to be extended to include customer facilities due to the increased use of power electronic based end-user equipment. Applications concerns often evaluated include:

− overvoltages associated with normal capacitor energization.
− open line/cable end transient overvoltages.
− phase-to-phase transients at transformer terminations.
− voltage magnification at lower voltage capacitor banks (including customer systems).
− arrester duties during restrike events.
− current-limiting reactor requirements.
− system frequency response and harmonic injection.
− impact on sensitive customer power electronic loads.
− ferroresonance and dynamic overvoltage conditions.

Power quality symptoms related to utility capacitor switching include customer equipment damage or failure, nuisance tripping of ASDs or other process equipment, transient voltage surge suppressors (TVSS) failure, and computer network problems.

CAPACITOR BANK ENERGIZATION – COMMON WAVEFORMS

This section includes a number of representative transient power quality waveforms that deal with utility capacitor bank applications. Relevant information and waveform characteristics are also provided.

Figure 1 shows a measured 4.16kV distribution bus voltage waveform during a utility capacitor bank energizing event. The resulting transient voltage was 1.35 per-unit (135%) and steady-state voltage rise was approximately 1.2%.

Figure 1 – Distribution substation capacitor bank energizing voltage waveform

Figure 2 shows a measured 13.8kV distribution feeder current waveform before-and-after energization of a pole-mounted 900 kVAr capacitor bank. Insertion of the bank creates a resonance that results in higher levels (13% THD) of current distortion.

Figure 2 – Distribution feeder capacitor bank energizing current waveform

Figure 3 shows a measured 23kV distribution feeder current waveform during back-to-back switching of two 1.8 MVAr capacitor banks. The conductor between the capacitor banks is approximately 4200 feet of 336 MCM aluminum tree wire.

Figure 3 – Back-to-back capacitor bank switching current waveform

Figure 4 shows a measured distribution substation bus voltage waveform during a multiple restrike event on a 34.5kV capacitor bank switch. The worst-case transient overvoltage was approximately 1.55 per-unit (155%). MOV arresters were installed on the substation transformer.

Figure 4 – Capacitor bank switch multiple restrike voltage waveform

Figure 5 shows a measured voltage waveform during the energization of a 300 kVAr, 15kV distribution feeder capacitor bank. The long pole span (time between phases closing) is because the capacitor bank is switched with three single-phase oil switches.

Figure 5 – Distribution feeder pole-mounted capacitor bank energizing voltage waveform

Figure 6 shows a simulated customer secondary bus voltage waveform (≈3.0 per-unit) during utility distribution substation capacitor bank switching. The customer has power factor capacitors (no arresters) and voltage magnification occurs.

Figure 6 – Customer secondary voltage waveform during utility capacitor bank energizing

Figure 7 shows a measured distribution bus voltage waveform during a multiple restrike event on a 34.5kV capacitor bank. The bank is protected with MOV arresters and the worst-case transient voltage was approximately 1.98 per-unit (198%).

Figure 7 – Distribution capacitor bank restrike voltage waveform

Figure 8 shows a measured distribution substation transformer secondary current waveform during a multiple restrike event (see corresponding voltage waveforms in Error! Reference source not found.) on a 34.5kV capacitor bank. The bank is protected with MOV arresters.

Figure 8 – Distribution capacitor bank restrike current waveform

Figure 9 shows a distribution substation transformer secondary current waveform during the energization of two distribution capacitor banks. The peak current on the CT secondary circuit was 401 A.

Figure 9 – Distribution substation capacitor bank energizing current waveform

Figure 10 shows a measured distribution substation transformer secondary current waveform during the energization of a distribution capacitor bank. The harmonic distortion of the steady-state current after the capacitor bank switching is approximately 11%.

Figure 10 – Distribution feeder capacitor bank energizing/resonance current waveform

Figure 11 shows a distribution bus voltage waveform during energization of a utility 34.5kV capacitor bank with another bank on the same bus. The resulting transient voltage and voltage rise were 1.5 per-unit (150%) and 1% respectively.

Figure 11 – Distribution substation capacitor bank back-to-back switching voltage waveform

Figure 12 shows a measured distribution feeder current waveform for an arcing capacitor bank switch during energizing of a 300 kVAr pole mounted capacitor bank on a 4.16kV distribution feeder.

Figure 12 – Distribution feeder arcing capacitor bank switch current waveform

Figure 13 shows a measured distribution feeder current waveform during energization of a distribution capacitor bank. The resulting peak transient current was 561 A and the full load capacitor bank current was approximately 65 amps rms.

Figure 13 – Distribution feeder current waveform during capacitor bank switching

Figure 14 shows a measured distribution feeder voltage during energization of a 4.16kV distribution capacitor bank. The resulting transient voltage was 1.48 per-unit (148%) and the steady-state voltage rise was approximately 0.4%.

Figure 14 – Distribution feeder capacitor bank energizing voltage waveform

SUMMARY

There are many events that can cause a power quality problem. Analysis of these events is often difficult due to the fact that the cause of the event may be related to a switching operation within the facility or to a power system fault hundreds of miles away. This document summarizes several of the more common power quality transient waveforms associated with the application of utility system capacitor banks. The frequent switching of utility capacitor banks coupled with the increasing application of sensitive customer equipment has led to a heightened awareness of several important events, including voltage magnification and nuisance tripping of ASDs.

These concerns have become particularly important as utilities institute higher power factor penalties, thereby encouraging customers to install power factor correction capacitors. In addition, nontraditional customer loads, such as ASDs, are being applied in increasing numbers due to the improved efficiencies and flexibility that can be achieved. This type of load can be very sensitive to the transient voltages produced during capacitor switching.

REFERENCES

G. Hensley, T. Singh, M. Samotyj, M. McGranaghan, and T. Grebe, Impact of Utility Switched Capacitors on Customer Systems Part II – Adjustable Speed Drive Concerns, IEEE Transactions PWRD, pp. 1623-1628, October, 1991.

G. Hensley, T. Singh, M. Samotyj, M. McGranaghan, and R. Zavadil, Impact of Utility Switched Capacitors on Customer Systems – Magnification at Low Voltage Capacitors, IEEE Transactions PWRD, pp. 862-868, April, 1992.

T.E. Grebe, Application of Distribution System Capacitor Banks and Their Impact on Power Quality, 1995 Rural Electric Power Conference, Nashville, Tennessee, April 30-May 2, 1995.

M. McGranaghan, W.E. Reid, S. Law, and D. Gresham, Overvoltage Protection of Shunt Capacitor Banks Using MOV Arresters, IEEE Transactions PAS, Vol. 104, No. 8, pp. 2326-2336, August, 1984.

S. Mikhail and M. McGranaghan, Evaluation of Switching Concerns Associated with 345 kV Shunt Capacitor Applications, IEEE Transactions PAS, Vol. 106, No. 4, pp. 221-230, April, 1986.

T.E. Grebe, Technologies for Transient Voltage Control During Switching of Transmission and Distribution Capacitor Banks, 1995 International Conference on Power Systems Transients, September 3-7, 1995, Lisbon, Portugal.

Electrotek Concepts, Inc., An Assessment of Distribution System Power Quality – Volume 2: Statistical Summary Report, Final Report, EPRI TR-106294-V2, EPRI RP 3098-01, May 1996.

Electrotek Concepts, Inc., Evaluation of Distribution Capacitor Switching Concerns, Final Report, EPRI TR-107332, October 1997.

RELATED STANDARDS
IEEE Standard 18-1992, IEEE Standard 1036-1992
ANSI/IEEE Standard C37.012-1979, ANS/IEEE C37.99-1990

GLOSSARY AND ACRONYMS
ASD: Adjustable-Speed Drive
PWM: Pulse Width Modulation
MOV: Metal Oxide Varistor
TVSS: Transient Voltage Surge Suppressors

Introduction

Construction of amorphous transformers

Energy savings and economic profits of amorphous transformers

Conclusions

INTRODUCTION

STUDY METHODOLOGY

MODEL DEVELOPMENT

SIMULATION RESULTS

SUMMARY

Why are meters stolen?

How are meters stolen?

How to get your meter back?

Other problems related to electricity theft

Introduction

Wiring Example

1.Introduction

2.Construction

3.Design

4.Application

5.Conclusions

INTRODUCTION

SIMULATION RESULTS

SUMMARY

PQ Monitoring

Fault Location

Storing Circuit Models

Integrating Data

Fault Circuit Indicators

Early Detection

Central PQ System Benefits

Summary

Introduction

Statistical data on consumption

Proposal of a hybrid system to power public lighting the village

Conclusion

1.Introduction

2.Setting coordination of inverse-time over-current relays

3.Simulation analysis considering inverse-time relays

4.Conclusion

5. Acknowledgements

INTRODUCTION

CAPACITOR BANK ENERGIZATION – COMMON WAVEFORMS

SUMMARY