A mature electrical network: Italian case of Enel Distribuzione, from insulated to ... Primary Substations in Enel Distribuzione, HV network considerations ............
POLITECNICO DI MILANO Scuola di Ingenieria Industriale e dell’Informazione Corso di Laure Magistrale in Ingegneria Elettrica Dipartimento di Energia
Feasibility for the introduction of current limiting impedance for a previously solid grounded medium voltage distribution network
Relatore: Prof. Dario Zaninelli
Tesi di Laurea Magistrale di: Alex Enrique Castro Gómez Matr: 822558
ACADEMIC YEAR 2015/2016
2
Abstract
The main target of the thesis work is to demonstrate the feasibility for the introduction of a current limiting impedance in a previously solid grounded distribution system, the network used is the IEEE 34 bus feeder test network. It is explored the main features of protection equipment and systems, and the current trends in the practice of protection engineering. In the thesis is analyzed the different approaches for grounding the distribution system and insulation coordination considerations. The above-mentioned topics are treated in the chapter one and two.
A bibliographic research is presented to highlight the main reason and motivations to change the present grounded method in the distribution system. The safety issues and the quality of services aspects are described as the main reason to develop a change in the grounded method of the network. The Italian distribution case, which is a matured network, is presented to analyze the main benefit obtained with the compensated grounded method, which is accompanied with an entire reconsideration of the protection and automation practices in the distribution network, the Italian case presents the particularity that the main driving force to modify the previous insulated grounded system is the quality of service policy established by the national regulator authority. The Brazilian case of AES do Sul is shown to indicate the first steps that a distribution system, which was a solid grounded approach, has performed to introduce a resonant grounded system, the principal reason to change the grounding method is based on security issues since there have been several problems with the ground overcurrent approach related to a lack of sensitivity by the presence of fault resistance, the overvoltages occurred in the new resonant grounding system constitute one of the main constraints to implement the new grounding approach since the system was designed for a solid grounding operation. The bibliographic research is analyzed in chapter three.
In chapter four is sizing the compensated grounded scheme to be used according to with the features of the IEEE 34 bus feeder test network. Since the network is based on overhead conductor lines, the compensated system is based just on a resistance. It is analyzed the overvoltages presented in the network, the main concern in the introduction of the compensated resistance is the highly increase in the residual voltages, which present unfeasible values in the phase to ground voltages that connect the monophasic loads.
The modifications in the loads to make feasible the introduction of the compensated resistance are presented in chapter five. In this chapter is analyzed the protective margins of the surge arrester required to operate in accordance with the compensated grounded scheme.
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Sommario
L'obiettivo principale della tesi è dimostrare la fattibilità per l'introduzione di una impedenza di limitazione della corrente in un sistema di distribuzione a terra precedenza solida, la rete utilizzata è la rete di prova alimentatore bus IEEE 34. Si è esplorato le caratteristiche principali dei dispositivi di protezione e dei sistemi, e le attuali tendenze nella pratica della tecnica di protezione. Nella tesi viene analizzato i diversi approcci per la messa a terra le considerazioni del sistema di distribuzione e di coordinamento di isolamento. Gli argomenti di cui sopra sono trattati nel capitolo uno e due.
Una ricerca bibliografica è presentato per evidenziare il motivo principale e motivazioni per modificare il metodo di messa a terra del sistema di distribuzione. I problemi di sicurezza e la qualità dei servizi aspetti sono descritti come il motivo principale per sviluppare un cambiamento nel metodo a terra della rete. Il caso di distribuzione italiana, che è una rete maturato, viene presentato per analizzare il principale vantaggio ottenuto con il metodo a massa compensato, che si accompagna con un'intera riconsiderare le pratiche di protezione e automazione nella rete di distribuzione, il caso italiano presenta la particolarità che la principale forza trainante per modificare il sistema di messa a terra isolata precedente è la qualità della politica di servizi stabilito dall'autorità nazionale di regolamentazione. Il caso brasiliano di AES do Sul è mostrato per indicare i primi passi che un sistema di distribuzione, che era un solido approccio con messa a terra, si è esibito di introdurre un sistema di messa a terra di risonanza, la ragione principale per modificare il metodo di messa a terra si basa su questioni di sicurezza in quanto non vi sono stati diversi problemi con l'approccio sovracorrente di terra connessi alla mancanza di sensibilità dalla presenza di resistenza di guasto, le sovratensioni sono verificati nel nuovo sistema di messa a terra di risonanza costituiscono uno dei principali vincoli per attuare il nuovo approccio di messa a terra in quanto il sistema è stato concepito per un operazione di messa a terra solida. La ricerca bibliografica è analizzato nel capitolo tre.
Nel capitolo quattro è il dimensionamento del sistema di messa a terra compensata da utilizzare in base alle con le caratteristiche della rete di prova alimentatore bus IEEE 34. Poiché la rete è basata su linee conduttore aereo, il sistema compensato si basa solo su una resistenza. Si è analizzato le sovratensioni presenti nella rete, la preoccupazione principale nell'introduzione della resistenza compensato è altamente aumento delle tensioni residue, che presentano valori irrealizzabili nella fase a tensioni di terra che collegano i carichi monofasiche.
Le modifiche nei carichi per rendere possibile l'introduzione della resistenza compensata sono presentati nel quinto capitolo. In questo capitolo viene analizzato i margini di protezione dello scaricatore di sovratensioni necessaria al funzionamento in conformità con lo schema a terra compensata.
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Acknowledgements
First of all, my acknowledgements to the Ecuadorian government agency SENESCYT, by means of the scholarship granted to me, I have been able to develop the master degree program at POLIMI.
I would like to express my deepest gratefulness to Prof. Zaninelli whom support has been vital to developing this thesis work. Special thanks to Prof. Pasini for the support to obtain the software to develop the simulations of chapter four and five.
I’m happy to share with my wife the experience of knowing another country and culture, thanks my beloved Maria Antonieta for all your patience and love. To my parents Marjorie and Enrique, thanks for all your prayers.
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Table of Content
1.
General features of protection system ........................................................................................... 9 1.1
Information requirements for protection studies ................................................................. 9
1.2
Primary protection, back-up protection, and protection zones ..................................... 10
1.3
Main requirements of protection systems ........................................................................... 12
1.4
Numerical protection relays..................................................................................................... 15
1.4.1
Brief description in the evolution of protective relays ............................................. 15
1.4.2
Main components of numerical protection relays ..................................................... 17
1.5
2.
3.
Current trends in the protection systems ............................................................................ 21
Grounding methods in medium voltage networks .................................................................... 23 2.1.
Insulated medium voltage networks ..................................................................................... 24
2.2.
Solid grounded medium voltage networks .......................................................................... 27
2.3.
Resistance grounded medium voltage networks .............................................................. 28
2.3.1.
High resistance grounding (HRG) .................................................................................. 29
2.3.2.
Low resistance grounding................................................................................................ 30
2.4.
Impedance grounded medium voltage networks, Petersen coil approach................. 32
2.5.
Insulation coordination and surge arrester considerations ........................................... 36
Modification on the grounding method in Distribution Networks. ........................................ 39 3.1.
Motivations for changing the grounding method .............................................................. 39
3.1.1.
Safety issues........................................................................................................................ 39
3.1.2.
Quality of Service ............................................................................................................... 40
3.1.3.
Service quality regulation: General concepts ............................................................. 42
3.1.4.
Service quality regulation: Italian case......................................................................... 45
3.2.
Improvements in the distribution network under the Smart Grid approach ............... 47
3.2.1.
Definition of Smart Grid and conceptual model ......................................................... 47
3.2.2.
The role of communication infrastructures in Smart Grid....................................... 49
3.2.3.
The Standard IEC 61850 .................................................................................................... 52
3.2.4.
Smart Grid projects in Italian Distribution Networks. ............................................... 53
3.3. A mature electrical network: Italian case of Enel Distribuzione, from insulated to compensated grounding system ........................................................................................................ 59 3.3.1.
Primary Substations in Enel Distribuzione, HV network considerations ............ 59
3.3.2.
Basic protection scheme of Primary Substation ....................................................... 61
3.3.3.
Introduction of the Petersen Coil approach ................................................................ 64
3.3.4.
Directional earth protection scheme, the new approach of Enel........................... 72 7
3.3.5.
Secondary Substation and Automation techniques ................................................. 76
3.3.6.
Benefits of the Petersen Coil approach ........................................................................ 79
3.3.7.
Enel Communication Network......................................................................................... 81
3.3.8.
State of the Art in Italian Distribution Systems .......................................................... 82
3.4. First steps towards the change: Brazilian case, from solid to compensated grounding system .................................................................................................................................. 87 3.4.1.
Motivations to change the actual grounding method in AES Sul network ......... 88
3.4.2.
Resonant grounding method applied in the network of AES Sul .......................... 90
3.4.3.
Overvoltages issues in the resonant network ............................................................ 92
4. Analysis of IEEE 34-bus feeder test network with solid grounded method and introduction of the compensated grounded system ......................................................................... 93 4.1.
Description of the IEEE 34-bus feeder test network ......................................................... 93
4.2.
Design of the compensated grounded scheme.................................................................. 94
4.3.
Limitation of the overcurrent protection approach ........................................................... 99
4.4.
Introduction of the grounded directional protection ...................................................... 101
4.5
Analysis of the temporary overvoltages of the IEEE 34-bus feeder test network... 108
5. Reinforcement of IEEE 34-bus feeder test network with a compensated grounded system and conclusions ......................................................................................................................... 111 5.1.
Reinforcement in the distribution network to improve the quality of service .......... 111
5.2. Insulation coordination issues in primary substation equipment and distribution network .................................................................................................................................................... 118 5.3.
Conclusions ............................................................................................................................... 122
Annexes ...................................................................................................................................................... 126 Annex 1 Electrical characteristics of the IEEE 34-bus bar test feeder ....................................... 126 Annex 2 Time overcurrent curves for short circuit and ground faults ...................................... 131
Index of figures ......................................................................................................................................... 133
Index of tables ........................................................................................................................................... 136
Bibliographic References ....................................................................................................................... 137
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1. General features of protection system A protection system is a complete set of protection equipment and other devices intended to perform one or more specified protection functions, protection systems include one or more protection equipment, instrument transformers, wiring, tripping circuits, auxiliary supply and communication system, the circuit breaker are excluded [1].
The protection equipment refers to equipment that incorporate one or more protection relays and in case to be required, logic elements to perform one or more specified protection functions, protection equipment is part of a protection system. A protection relay is a measuring relay which, either solely or in combination with other relays, is a constituent of a protection equipment.
A protection scheme concerns to the collection of protection equipment which provide a specific function and includes all equipment necessary to make the scheme work (i.e. relays, CTs, VTs, CBs, DC system.) [2].
1.1
Information requirements for protection studies
In the design process of protection system, the first stage consist on the definition of the primary protection scheme, secondary protection scheme, and the protection zones. Some authors such as Blackburn recommend the following checklist of required information to begin with the design process [4]:
•
Single-line diagram of the system or area involved in the survey. The diagram shows the location of the circuit breakers, CT and VT, generators, buses, and transformers.
•
Impedance and connections of the electrical equipment, frequency, voltage, and phase sequence. This information is usually present in the single-line diagram, however, could be omitted the connection group and grounding of the power transformers.
•
Except for new, existing protection and problems. When the network is not new, the information about the existing protection system may require updating, integration with the new protections.
•
Operating procedures and practices. The new and modified protection system should satisfy the current practices and procedures.
•
Importance of the system equipment to be protected. The relevance of the equipment is mainly evaluated based on the size and the voltage rating of these. As a matter of fact, the more important the equipment that requires protection is to the network and its ability to remain in service, the more important it becomes to design a high-speed protection system.
•
Power flow study. It is necessary to know the maximum load that will be allowed to pass through the equipment during short-time or emergency condition for which the protection must not operate. The maximum load values should be in accordance with the ratings values of the equipment.
•
System fault study. The settings for several protection applications require a complete fault study of the network, in case of phase-fault protection, is required a three-phase fault study, while for ground-
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fault protection a single line to ground fault study is required. The fault study have to indicate the units (volts and amperes) at a specified voltage base, or in per unit with the respective base. •
CT and VT locations, connections and ratios. The locations of CT and VT is frequently shown in the one-line diagram, but not the specific tap or ratio in use, additionally, the grounding of the VT should be clear.
•
Future expansions. Should be indicated the growth or changes expected in the network that are likely to happen in order to find tolerable and intolerable operating conditions.
It is important to remark that not all of the above-mentioned items are strictly necessary for a defined problem or network requirement, nevertheless, the checklist constitute a support in providing a better understanding of the protection issues [4].
Once defined the information necessary to develop the protection system study the next step is the definition of the primary protection, secondary protection and the protection zones of the network under evaluation.
1.2
Primary protection, back-up protection, and protection zones
The main target of protection systems it is to isolate the faulted areas in the electrical network in the fastest way possible, hence the effects of the several faults that could be present in the electric network are decreased. Relays defined as unit type protection, operate only for faults located within their protection zone. The relays designated as non-unit protection are capable to detect faults within its own protection zone and outside it (mainly in adjacent zones), in this way the non-unit protection relays can be used to back up the primary protection [5].
Primary protection: The scheme of primary protection has to operate every time a relay detects a fault in the network, this scheme protects one or more equipment of the power system (e.g. electrical machines, bus bars, and lines). According with the importance of the equipment, it is feasible to have various primary protection devices, but this does not means that all the primary protections should operate for the same fault. It is necessary to highlight that the primary protection for one specific element to be protected not necessarily is installed at the same location as the elements, is possible that can be located in an adjacent substations [5].
Back-up protection: Also known as secondary protection, is installed to operate when, for any circumstance, the primary protection does not perform its task. To reach this goal, the back-up protection relay has a sensor element which may be similar to the primary protection, also should include a time-delay characteristic to slow down the operation of the back-up relay so as to allow time for the primary protection to operate first. One relay can provide back-up protection at the same time for different elements of the network. Is frequently that a relay works as primary protection for one piece of equipment and as back-up for another [5].
Protection zones: The general practice to design protection system consists in dividing the system into separate zones, see figure 1.1, which can be individually protected and disconnected when a fault occurs, in order to allow the remain system to continue in service. The electrical network is divided into protection zones
10
for generators, power transformer, group of generator-step up transformers, motors, bus bars, and lines. The figure 1.2 presents an electrical network with six protection zones. It is important to realize that the zones overlaps among them, specifically overlap in the circuit breaker positions, therefore, in case of fault in these overlapped zones, more than one set of protection relays will operate. The protection zones overlapping is achieved by connecting the protection relays to the appropriate location of current transformer, the figure 1.3 shows this detail [5].
Figure 1.1 (Definition of protection zones)
Figure 1.2 (Overlapping of protection zones)
In the best cases the protection zones are conceived to overlap, in this way there are no parts of the electrical network left unprotected, however in some cases for practical reason (technical and economic) overlapping of the zones in the circuit breaker is not achieved, the location for current transformers is available in only one side of the circuit breaker, the figure 1.3 indicates this situation, in the graph is shown that the section between the CT and the CB is not fully protected against faults.
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In the event of fault in the point F would produce the operation of the bus bar protection and the opening of the circuit breaker but the fault may continue to be fed through the feeder. In case that the feeder protection just respond to faults within its own zone, it would not operate since the fault is outside its protection zone. This issue can be resolved with intertripping or extension of the protection zone in order to guarantee that the remote end of the feeder is also tripped and the fault at F is totally cleared [2].
Figure 1.3 (Overlapping limitations)
1.3
Main requirements of protection systems
In the stage of design and planning of protection systems it is necessary to fulfill the following requirements in order to obtain the best performance:
Reliability: There are two aspects that shape the concept of reliability, dependability, and security. According to the standard IEEE C37.100 dependability is the degree of certainty that a relay or relay system will operate correctly, meanwhile, security relates to the degree of certainty that a relay or relay system will not operate incorrectly [3].
The dependability expresses the ability of the protection system to work correctly when required, whereas security is its ability to avoid unnecessary operation during normal operation periods. The protection system should be designed quite well in order to discriminate between the tolerable transient that the network can operate through successfully, and those, such as light faults, that may result in major problem if not quickly isolated, in this sense, the protection must be secure (not operate on tolerable transient), yet dependable (operate on intolerable transient and permanent faults). Dependability is not so complex to verify by testing the protection system to assert that it will work as expected when the threshold values are exceeded, on the contrary security is more complicated to evaluate since there can be a considerable collection of transients that might disturb the protection system, and the forecast of all these scenarios is quite burdensome [4].
Selectivity: A protection scheme is selective when in the event of a fault must trip only the necessary circuit breakers that isolate the fault, allowing to the healthy part of the network to remain in service. The characteristic of selective tripping is also known as relay coordination, there is two approach to achieve the selectivity property [2] [4]:
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•
Time grading. The main target of the relays is to protect the equipment located in the primary protection zone assigned, but the relays can also operate in response to abnormal conditions outside this primary zone. This means, that the relay provide backup protection for the area outside their primary zone. Authors such as Blackburn define the relay coordination as the process of applying and setting the protective relays that overreach other relay such that they react as fast as possible within their primary zone with a delayed time operation in their backup zone (time grading approach), this is necessary to allow the primary relays assigned to this backup zone time to operate, otherwise, both set of relays may operate for faults in the overreached area. The operation of the backup protection is erroneous and undesirable unless the primary protection for a given protection zone fails to clear the fault [4]. In order to develop a correct protection coordination, it is necessary to have very clear the concept of clear fault time, which expresses the time to completely eliminate a fault when this occurs, it is defined as the sum of two time intervals [7]:
=
+
(eq. 1.1)
: Circuit breaker opening time, refers to the time interval between the energization of the opening release element and the moment when the circuit breaker contacts are completely separated in the all phases.
: Protection tripping time, indicates the time elapsed between the instant at which the faults occurs and the instant of sending the trip signal towards the opening release element of the circuit breaker. The relay protection tripping time has two components, an intentional set time delay introduced to time grading purposes (generally) and the base time of the protection relay.
The selectivity time between two protection relays that sense the same fault is defined as the time that should be delayed the back-up protection with respect to the primary protection. The selectivity time correspond to the sum of the followings time intervals [7]:
∆ =
+
+
+
+
(eq. 1.2)
Where: : Base time of the primary protection relay : Time based error of the primary protection relay : Circuit breaker opening time corresponding to the primary protection scheme : Overshoot time (or retardation time) of the back-up protection relay : Security margin
The figure 1.4 it shows the clear fault time and selectivity time between a primary and back-up protection relays.
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Figure 1.4 (Time grading selectivity)
•
Unit systems. According with the importance of the equipment in the network, it is possible to design protection system that respond only to fault conditions occurring within specific defined zone for that equipment. This type of protection system is called unit protection, some types of unit protection are best known by specific names such as restricted earth fault and differential protection. Unit protection schemes can be used throughout a network, since it does not involve time grading and it is relatively fast in operation response, usually involves comparison of magnitudes at the boundaries of the protected zone which are defined by the located of the current transformers, the comparison can be reached by direct hard-wired connections or may be reached by means of communications links. It must be kept in consideration that selectivity is not simply a matter of relay design, it also depends on the right co-ordination of current transformers and relay with an appropriate choice and calculation of relay settings [2].
Speed: The property of speed refer to the capability to isolate faults on the network as fast as possible, taking in consideration the continuity of supply by removing the faulted elements before it causes a widespread loss of synchronism and subsequent collapse of the network. The increase in the load on the power system cause that the phase shift between the voltages at different bus bars also increase (e.g. bus bars for transmission lines), consequently, the probability that synchronism will be lost when there is a fault in the network increase too. In this sense, meanwhile the shorter the time interval a fault is allowed to remain in the network, the greater can be the loading of the system. The energy released during a fault is proportional to the time interval that the fault exist, therefore it is critical that the protection operates as rapidly as possible. Fast operation of protection system assure a minimization of the equipment damage caused by abnormal condition in the power system [2].
Simplicity: In the design stage the protection system should be planned and designed in a simple and straightforward way as possible, keeping the main protective targets. Every addition in the protection system that is not necessarily basic to the protection requirements and offer improvements in the protections should be rigorously analyzed. Each addition represents a potential source of trouble and additional maintenance. All of further elements have to be assessed to guarantee that they absolutely help to enhance the protection system [4].
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Economy: The engineering process to design a protection system is subject to economic constraints, in this sense, the target consist in obtain the best protection system possible with the minimum cost. Generally, the cost associated to the protection system are considered high, however, these costs should be compared with the cost of the protected equipment, the cost associated to an outage and severe damage in the equipment due to improper or low quality protection devices. Therefore the savings that could be obtained in the cost of protection system may result in considerable amount of cash flow to replace or repair the equipment damaged due to inadequate or inappropriate protections [4].
1.4
1.4.1
Numerical protection relays
Brief description in the evolution of protective relays
The invention of the transistor (1947) introduced a great advances in the protection relay technology, the transistor allowed the development of the static protection relays (no moving part such as electromagnetic relays, with the exception of the output element) and with this, the second era of protection relays began. The static relays share the operational criteria of the electromagnetic ones, nevertheless, the trip order (or no tripping order) were based on the new ways of signal processing, the second generation of relays offered advantages such as enhancement of cooperation with CTs and VTs, reduced dimensions and modularity of the protection relays, improvement for the testing procedures (also in maintenance and repair), complex operational features, increased speed of operation as the most important characteristic [8].
W. Rebizant et al [8] present a brief history of protection technology (figure 1.5). A overcurrent and under voltage relays with CTs and VTs, B inverse time overcurrent relays, C differential relays and directional relays, D distance relays with time grade features, E static relays (include filter and comparator), F digital relays measuring phasors, G first wide-area measurement protective system.
Figure 1.5 (4th generation digital relay structure [8])
15
It is important to note that the operation of the first and second generation of protective relays were based on comparators, the comparator just decided if the current or voltage waveform was smaller or greater than the operation threshold. For digital relays, the signals are completely measured and the comparison with the thresholds come afterward. From 1985 the digital relays start to become the main offered protective relay of the manufacturers [8], these new type of relays offer advantages such as integration of functions (protective functions), decreasing of the power consumption from secondary terminals of CTs and VTs, decreasing of secondary cabling, complex algorithms to process digital signals using values of the samples, improvements of the operation speed, communication capabilities, and self-testing capabilities.
The technical and economic improvement in digital processors and memory applications thrust the third generation of protection devices (digital relays). For these relays, the digital processing of input signals are executed in five steps:
•
The input signals that come from CTs and VTs enter the antialiasing low-pass filter that remove components of high frequency.
•
The signal at the output of the anti-aliasing low-pass filter enters the analog to digital converter (A/D), and at the output of the A/D, the signals have been converted in train of samples (digital signal).
•
The digital signals is filtered and orthogonalized in the initial processing block.
•
The outcomes of the initial processing arrive to the block of digital measurements, in this block are calculated the criteria signals, specific parameters, and mutual relations.
•
The last block produces the protection decisions, which are based on comparison between the calculated criteria values and the pre-set thresholds or other comparable feature.
Nevertheless, for the digital protective relays, the microprocessors had limited processing capabilities and associated memory (in comparison with numerical relays), hence, the functionality is limited mainly to the protection function itself [2]. But, in relation to an electromechanical or static relay, digital relays had a wider range of settings, greater accuracy and communication capabilities that allowed it to the integration with automatized system [2, 4].
According to big manufacturers such as Alstom, improvements in the technology allow to the digital relays moved to what is now known as numerical relays, the main differences between digital and numerical relays lays on features of very specific technical details and is barely found in areas other than protection. The numerical relays can be considered as the expected improvements of the digital relays since the continuous progress in the microprocessors technology. One of the main feature of the numerical relays is the use of one or more digital signal process, which is optimized for real-time signal processing, executing the mathematical algorithms for the protection functions. Therefore, advanced microprocessors allow to the numerical relays perform several relay functions such as overcurrent, earth fault or over-voltages, these relays functions as known as relays elements. Each relay element is developed in software, in this way, with modular hardware the main signal processor can perform an extensive variety of relay elements [2]. Figure 1.6 presents the several relay functions for a protective relay GE multilin.
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Figure 1.6 (Relays elements of numerical relay GE C60)
1.4.2
Main components of numerical protection relays
The operation of the numerical relays is mainly based on the sample of inputs and controlling the outputs (e.g. trip or close command towards the CB) to control and protect the equipment or system. The currents and voltages are not monitored on a continuous basis, but are sampled for the relay, after acquiring samples of the input waveforms, calculations are developed to convert the sampled values into a final value that represents the input magnitude based on a defined algorithm, once the final value of an input magnitude is determined, the comparison to setting or other command is performed by the relay. In order to obtain a better understanding of the numerical protective relays it is necessary to know the main components, which are divided in the following blocks [9]:
•
Analog antialiasing filtering
The sampling process of voltages or current signals need to consider the frequencies of interest contained in the input signal (voltage or current). The higher frequency components of the input signal may be incorrectly represented as a lower frequency components. The aliasing is defined as the impact of a highfrequency signal component that appears as a low-frequency signal. In order to mitigate this effect, a convenient sampling rate have to be chosen and the maximum required frequency component of the input signal should be identified (generally identified as
), all higher frequency components will be attenuated
by the low pass filter. The anti-alias filter refers to a low pass filter to attenuate the high frequency components when sampling [8].
The cut-off frequency of the filter
should meet the following condition:
<
≤
(eq. 1.3) 17
Where
is the sampling frequency, this produce that all the components with frequencies lower than fk
pass with minimal distortion and the components with frequencies greater than fs would be annulled [12].
In the figure 1.7 is presented a general overview of the frequency response of low-pass filter, the frequency response may present flat characteristic in the pass and reject regions (errors e1 and e2), in most cases the analog input filter are designed in form of cascade RC circuits [8].
Figure 1.7 (Frequency response of low-pass filter [8])
•
Sampling process and A/D conversion The fundamental frequency component of the input signal contains the useful information to be measured and processed, in many cases is necessary to know some higher frequency components such as 2nd, 3rd, or 5th. Hence, all the other frequency component of the signal have to be discarded. The frequency component of signal with high frequencies close to the sampling frequency are considered dangerous because of these may produce irreversible deformation of the digital signal. The above mentioned implies that the choice of the sampling frequency fs is a trade-off. The sample frequency should not be too low in order to allow the construction of the components that are important for the relay process (protection or control). Moreover, the sample frequency should not be too high in order to avoid unrequired burden for the digital processing [9].
The Shannon-Kotielnikov theorem provides the criteria to set the minimum sampling frequency, this states the conditions that allow to the signal be constructed after sampling. Therefore, there should be at least two samples of the input signal within the period of the signal component that have to be represented in digital form without loss of information regarding the frequency [12]. This implies that, if the component that is required to be reproduced in a correct way has a frequency , then the sampling frequency have to be:
≥ 2
(eq. 1.4)
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The sampling process (extract of sample values in time domain) has important result in the frequency domain. It is possible to demonstrate that the spectrum of the analog signal becomes duplicated after signal sampling. The sampled signal spectrum correspond to a sum of copies of original spectrum shifted left and right by a multiple of sampling frequency, according to: ∗
"
! = ∑/1 #
/ /%& / '
!(')*−
−,
"
! -. 0 = ∑/1 #
/
*
−,
!- (eq. 1.5)
This characteristic of digital spectrum is showed in the figure 1.8. It is possible to conclude that the analog signal can be reconstructed from its samples only when the copies of original spectrum are separated one from another, this coincides with the Shannon-Kotielnikvo sampling theorem
Figure 1.8 (Illustration of sampling process in time and frequency domains [8]) Once the signal has been sampled, its value is discretized in time, however, the value remain analog. This analog value will be converted into a digital one by means of the A/D converter, the digital form of the signal value has a finite number of digits, and this conversion is necessary to further processing in the relay (digital signal processing block). The current technology of protective relays presents one A/D converter which is employ even if many channels for numerous signals have to be processed. The A/D converter is switched sequentially to the channel by means of a multiplexer and analog memory (in some case is a capacitor bank), the figure 1.9 presents this scheme.
Figure 1.9 (A/D converter with analog memory and multiplexer [8])
19
The A/D converter has two basic parameters: o
Number of bits m, known as the world length of A/C converter
o
Converter range M.
The converter resolution is obtained by means of the parameters m and M, the grain of the conversion is defined as:
. =
2 34 "
(eq. 1.6)
From the equation 1.6, it can be seen that higher resolution (lower grain) is obtained for higher number of bits m. In case that the signal changes in wider range, the resolution for the same number of bits gets lower. This explains the higher number of bits that the A/D converter should have for current signals [8].
•
Digital signaling processing The digital processing of sampled input signals defines the protection operation that determine the status for the protected system (healthy or faulty) and the final protection decision (i.e. trip order, close order).
The protection criteria measurement algorithm can be grouped into four main families, as shown in the figure 1.10. It can be seen that the first step of signal processing is generally filtering out of signal components that are expected to carry the information regarding the protected system status, the other components are processed as noise and are rejected or suppressed. After this process, the criteria values are calculated either by signal averaging or by using measurement algorithms based on orthogonal components of the signals [8, 12].
Figure 1.10 (Techniques of protection criteria measurements [8])
20
1.5
Current trends in the protection systems
The gradual efficiency of the microprocessor and the permanent advances in telecommunication have allowed the development of the 4th generation of protective devices. The new features of protective relays have supported to the development of the Wide-Area Measurement and Protection System (WAMPS), which incorporate the advancements in digital processing with the fast and reliable exchange of information by means of telecommunication links [8, 10].
Among the main features of the last generation of protective relays can be mentioned the followings: •
Wide area measuring of signals and transfer regarding to the outcomes of the decision-making process.
•
Integration of protection, control, monitoring and measurements
•
Adaptability to the existing conditions.
•
Intelligent decision, estimation of actual conditions and possible consequences of wrong decisions.
The communication system became a critical function in the performing of the protection equipment, the communication can be made by means of wires, high-frequency radio signals or optical fibers. Nowadays, besides the previously features that have to fulfill a protection system, the protective devices from different manufacturers can communicate and understand each other. This problem can be solved by the introduction of common communication standards, the most used and know standard is IEC 61850 for communication within a substation [8, 10].
Authors such as Rebizant [10] states that the 4th generation arrive in the opportune time since the philosophy of relaying has recently slightly changed, previously the main target of the protective relays was to assure reliable and fast protection of given equipment in the network, the relays were object-oriented. At the present time, the priorities of relaying are slightly shifted. The main priority is protection of the power system against developing disturbances (to avoid the possibilities of blackout). Although the target for protecting a given component of the networks is still crucial, however, the relays ought to be system oriented. Hence, undesirable tripping may be considered as dangerous as the delayed tripping of the fault.
Among the main functions of the Wide-Area Measurement and Protection System can be mentioned the followings [8, 11]:
•
Adaptive protection system with adjustment to various network topologies
•
Wide area differential protection embracing network objects over a number of voltage levels
•
Global decisions making based on exchange of information
•
Short circuit detection and location at relaying center
•
Application of adaptive protection settings
•
Monitoring of system stability and connection with substation automation system
21
The current trends in substation automation technology is concerning to substation control and remote control, the substations apply an intelligent electronic devices capable to build an open communication system operated centrally with a PC and communicate with a higher level control center [13].
From a wider perspective, the structure of power system control is a hierarchical structure with vertical connections as shown in fig 1.11. Current protection and control systems within substations are able to create horizontal links by means of common data bus for a considerable data exchange traffic between feeder/object level devices, see figure 1.12.
Figure 1.11 (Protection and control hierarchical structure [8])
Figure 1.12 (System function architectural diagram [8])
The IEDs that conform the protection and control system of the substation are either LAN enabled or are connected to the data bus by means of the network interface module devices, a huge quantity of information is stored in the data concentrator. The substation data can be remotely accessed from exterior, time referenced (GPS) and used in SCADA applications. The operational and non-operational data are able to be transmitted to the corporate Data Warehouse that allow to the user to get access for substation data, taking into account that it is necessary the provision of firewall to substation control and operation functions [8].
22
2. Grounding methods in medium voltage networks The neutral management method and the operation voltage are among the main features of the medium voltage networks, once chosen it is very difficult to change these features since implies a considerable financial challenge. Nevertheless, the pursuing of improvement in safety and quality of service may justify a review of the neutral mode applied in the system.
The standard IEEE C62.92.4 classifies the distribution systems in two groups, grounded and ungrounded. The ungrounded systems present the secondary windings of the primary substation transformer connected either in ungrounded delta or ungrounded wye. Grounded systems frequently are obtained from the primary substation transformer with wye-connected windings and the neutral point of the windings solidly grounded or connected to ground by means of a non-interrupting current limiting devices [14].
Grounded distribution system are divided in 4-wire systems and 3-wire system. In case of 4-wire system, the circuit is constituted by the three phases and neutral conductor, the neutral conductor of the distribution feeder may be connected to earth at several points (multi-grounded) or may be connected to earth only in the primary substation (uni-grounded). For three-wire uni-grounded systems, the circuit is run without the neutral conductor and the grounding connection is done in the primary substation [14]. Figure 2.1 indicates the basis scheme of the grounded systems.
Figure 2.1 (Grounded scheme types)
The neutral connection method employed in the primary distribution substation (HV/MV transformer) has influences in the following parameters of the distribution system:
•
One phase to earth fault: the neutral connection type of the primary distribution transformer have a direct effect in the determination of the one phase to earth fault, since affects the impedance in the zero sequence circuit, even more, the introduction of impedance connected to the neutral point of the transformer.
23
•
Touch voltage: This parameter concern the safety of persons in the proximity of an electrical fault. The touch voltage is directly related to the value of the earth fault current and the impedances through which the one phase to earth fault flows.
•
Overvoltage level: this abnormal connections is studied when occurs a one phase to earth fault, depending on the neutral method used are presented considerable values of overvoltage in the distribution system, this parameter should be studied in order to determine the rated value of the surge arrester along the distribution feeder and consequently in the insulation of the distribution system in general.
The three parameter above mentioned indicate that the neutral method in the distribution systems has no greater effect in the normal operation of the distribution feeders. The neutral method is highly important to determine and design the distribution systems for abnormal conditions taking into account the remarkable impact in the security and safety of the network and public in general. The selection of the neutral method for distribution systems are done based on local requirements regarding the extension of the underground and overhead networks.
Around the world, the countries use different neutral methods according to their specific needs. In US, some countries of South America and Australia is used the scheme of 4-wire networks with the neutral connected directly to earth at several point (multi-grounded) [6].
In Europe, the 3-wire approach (grounded or ungrounded) is used. The 3-wire networks use four types of earthing [6]: •
Isolated neutral
•
Directly earthed neutral
•
Resistance or Reactance low impedance neutral
•
Compensated neutral
According with the research of EPRI Project 1209-1, “Distribution Fault Current Analysis”, the most of the faults on distribution network lines only affect one phase, more precisely, state that the 79% of faults on distribution lines only involves one phase [30]. Considered the above mentioned, the purpose of this chapter is present the main features of the 3-wire networks under abnormal conditions, specifically for one phase to earth fault.
2.1. Insulated medium voltage networks In the insulated system, there is not an intentional connection of the HV/MV transformer neutral. Under normal operating conditions there is not difference with respect the other 3-wire systems. The loads of the insulated neutral system are conformed by three phase loads in order to keep balanced the power flow in the feeders, in normal conditions and balanced loads the phase to ground voltages are equal in magnitude and shifted 120° among them, consequently the voltage difference between neutral and ground is zero.
24
When occurs a one phase to ground fault, the fault current flows from the HV/MV transformer (winding corresponding to the faulted phase) and returns by means of the stray capacitance to earth of the healthy phases of the feeder and the healthy phase stray capacitance of all the feeders connected to the same HV/MV transformer. This implies that the one phase to ground fault current magnitude depend on the faulted feeder parameters and the size of the rest of the system (stray capacitance to ground of the system) [6]. In the figure 2.2, it is observed the scheme for the ungrounded system under the one phase to ground fault condition.
Figure 2.2 (Capacitive currents under one phase to ground fault)
It is noted that the voltage at the neutral point (with respect to earth) is shifted and the magnitude correspond to the nominal value of the phase to ground voltage under normal conditions. In order to simplify the calculations the series reactance of the lines have been neglected, nevertheless author such as F. Gatta et al [16] take into account the effect of the series reactance of the feeder in order to obtain more realistic values for over voltages in the healthy lines and the magnitude of the one phase to ground fault current.
Figure 2.3 (voltage phasor in normal operation condition and one phase to ground faulted condition)
25
Figure 2.3 shows the increment in the voltage magnitude of the healthy phases (phase b and c) under one phase to ground fault condition, the increment in the voltage affects to all the feeders connected to the MV busbar (primary substation), therefore the system presents an unbalance condition of the voltage, where the phase a is faulted and the phase b and c presents over voltages, according to the figure 2.3 the over voltages in the healthy phases correspond to a factor of √3, this is one of the main reason to observe high insulation levels at ungrounded distribution system and is a disadvantage since it is necessary to increase the investment. According to literature [15], unearthed networks can presents over voltages higher than double the phase to ground normal voltage, this condition may lead to other adverse condition such as double phase to ground fault of cross country fault, since the insulation of the healthy phase may fail because of the over voltages condition.
Figure 2.4 (one phase to ground phasor diagram and magnitudes measured by residual CTs and VT)
The one phase to ground fault current correspond to the sum of the capacitive current of the healthy feeder and the faulty feeder as seen in figure 2.4, the fault current is independent of the location of the fault and is a function of the capacitance of the system.
|89: | = |8;: | = |8 : | = |8 < | = 1 ). ?. @9: = @;: = @ @ = @9:
A
CDE
B; = F B
GHDE
CGE
=F
GHGE
:
+ @9:
=@
(Phase to ground total capacitance of each phase)
(Total capacitance as the sum of the healthy and faulty component of each phase)
= I− 3 −
√ 3
J
@;:
CGE
= I− 3 +
√ 3
J
@
√ 3
J
@;:
B;A = F
= I− 3 +
√ 3
J
@
B
B L = B; + B;A = I− 3 − BML = B
CDE
= I− 3 −
+B
A =
I− 3 +
BN9OPQ = B L + BML = −3
√ 3 √ 3
J
J
:
A
=F
GHDK
GHGK
A
: A
@;: @
:
@ ). ?. = −3
@ 8)ℎ (eq. 2.1 [6]) 26
Equation 2.1 indicates a situation where is not considered a fault resistance, in case of presents of this resistance, the magnitude of the one phase to ground fault current will decrease.
Since the magnitude of the one phase to ground fault currents magnitude present a relative low value, it is necessary the use of a very sensitive protection scheme, which allow to detect the fault currents even in the present of considerable value of fault resistance. To reach this goal, the directional ground scheme is employ. The directional ground (67N in ANSI) requires a polarized reference in order to discriminate the faulty feeder from the healthy feeder, this magnitude is obtained from the secondary of the voltages transformer set installed at the MV bus bar of the primary substation, which detects the residual voltages (Va+Vb+Vc=3Vo).
Complementary, a residual CT has to be installed at each feeder in order to detect the residual current. The feeder residual current is compared with the polarized magnitude, and according with the polarization of the residual CT, it is established that in case the residual current lead the residual voltages, the feeder is in healthy state, on the contrary, if the feeder residual current is lagging the residual voltages this means that the feeder in question is faulted. The figure 2.4 presents the position of the residual current for healthy and faulty feeders with respect to the polarized magnitude (residual voltage).
2.2.
Solid grounded medium voltage networks
The solid grounded method presents a scheme where the neutral of the power transformer (medium voltage side) is connected to ground without any intentional impedance (resistance, reactance or combination of both) between the transformer neutral and the grounding electrodes. Nevertheless, the impedance of the source and the unintentional impedance in the connection to ground have to be assessed when studying the grounding system.
In order to evaluate the advantages of the solid grounded method, it should be estimated the degree of grounding provided in the system. A convenient reference is the comparison of magnitude of the one phase to ground fault current with respect to the three phase fault current, the higher the one phase to ground fault current magnitude with respect to three phase fault current, the greater the degree of grounding in the network, the one phase to ground fault current will be at least 60% of the three phase fault current magnitude [16].
Regarding the resistance and reactance parameters of the system, an effective grounding system is obtained when
S/ "
≤ 3 and US /
"
≤ 1 and such relationships exist at all points in the network, the
"
reactance
correspond to the thevenin equivalent positive sequence of the complete system including the subtransient
reactance of all machines, the US component is mainly three time the resistance of the connection to ground. Since the reactance of a solidly grounded generator or transformer is in series with the neutral circuit, the solid grounded connection does not bring a zero impedance circuit. In case that the reactance of the zero sequence circuit of the system is too high in comparison to the positive sequence reactance of the system, the goals of the solid grounded method are achievable, especially regarding to the reduction for over voltages [16].
27
Figure 2.5 (Sequence circuit of solid grounded distribution system) When the power transformer of primary substation is solidly grounded, it can be observed in the zero sequence circuit that the sum of the transformer and line zero sequence impedances are in parallel with the capacitance impedance of the line (equivalent feeder), as seen in the figure 2.5.
Generally, for distribution system, the capacitance impedance is much greater than the sum of the transformer and line zero sequence impedances, therefore, the capacitance impedance can be neglected, the total zero sequence impedance present a very low value compared to the value in the insulated grounded system, this is the mean reason that explains the high value for one phase to ground fault currents and the respective low value of over voltages in the healthy phases (in comparison with the insulated grounded system).
2.3. Resistance grounded medium voltage networks
For distribution network applications, the neutral of the power transformer in the primary substation is connected to ground by means of a resistor. Since the resistor increases the final impedance of the zero sequence circuit, there is a considerable reduction in the magnitude of the one phase to ground fault current, the reduction in the magnitude of the ground fault current will depend on the value of the resistance introduced. The higher the resistance the closer will be the current and voltage behavior with respect to an ungrounded network.
The standard IEEE 142 provides the following reasons to consider the reduction of the one phase to ground fault current magnitude through the resistance as a ground method [17]: •
Reduction in the burning and melting effects in faulted electric equipment
•
The mechanical stress in circuit and apparatus carrying fault current is decreased
•
Decreasing of electric shock hazards to personnel produced by stray ground fault currents in the ground return path
•
Reduction of the flash hazard to personnel who may have accidentally caused or occur to be in near proximity to the ground fault
•
Reduction in the momentary line voltage dip caused by the existence and clearing of a ground fault
28
•
Ensuring the control of transient overvoltages, additionally, it is avoided the shutdown of ta faulted circuit in the event of the first ground fault.
The resistance grounded method is divided in two classes, high resistance and low resistance, which are differentiated by the magnitude of the ground fault caused. Even though there are no recognized standards to classify the ranges of ground fault current magnitude for these two subdivisions, exist clear difference in practice.
2.3.1.
High resistance grounding (HRG)
A HRG power system use a resistance connected to the neutral of the power transformer of high ohmic value. The resistor is sized such that in present of one phase to ground fault, the resistive current flowing through the resistor has a magnitude equal to or slightly greater than the total capacitance charging current B [17, 18].
It is important to know the system charging current in order to size the neutral grounding resistor (NGR) U: , the equation 2.2 provides the condition to be fulfilled by the NGR [18, 21].
U: ≤ I
VWX YG
J Ω (eq. 2.2 [21])
Where:
[\] Line to neutral system voltage in volts;
B System charging current in amperes
In figure 2.6 it is presented a schematic network under a ground fault with the introduction of HRG.
Figure 2.6 (Capacitive and resistive currents under one phase to ground fault)
29
The introduction of the resistance limits the magnitude of the one phase to ground fault, the resistance should be sized taking in consideration the system charging current. In figure 2.7 present the phasor diagram of the current and voltages in the event of ground fault.
Figure 2.7 (current and voltage phasor in one phase to ground faulted condition)
Figure 2.6 and 2.7 present a medium voltage system with a healthy and faulty feeders, the NGR have been sized taking account the total system charging current, B approximate to B B^_) ` _a!. In the figure 2.7 it can
be noted that the residual CT measured the sum of the resistive current and the capacitive current from the equivalent healthy feeders. This residual CT measurements in combination with the residual voltage VT in the MV bus bar form the residual direction protection for each feeder. In this way, it can be reached the selectivity that identifies with feeder has faulted.
According with authors such as D. Paul, the HRG system should not be limited to networks with voltages less than 4.16 kV and the one phase to ground fault current to less than 10 A, as long as the faulted network is isolated in an interval of ten cycles and that there are no directly connected motors. The HRG systems are mainly used in industrial system such as mining, cold ironing, and ship on board power supplies [18]. By other hand, Foster et al indicate that the use of HRG on networks with one phase to ground fault current greater than 10 A should be avoided because of the potential damage produced by an arcing current greater than 10 A in confined spaces, this study was applied for cement industries [20].
In case of distribution networks consisting mainly of overhead feeders and lower values of capacitances current, it is used a simple resistance (approximate value of 770 Ω). This approach obtains a low phase to ground current magnitude and obtains a good probability of self-extension fault, elimination of arcing faults and reduction of temporary overvoltages [23].
2.3.2.
Low resistance grounding
This scheme is designed to reduce the one phase to ground current magnitude to a range between 100 A and 1000 A. 400 A is a typical value [17]. Figure 2.8 shows the basic scheme for a low resistance grounded system, the neutral grounding resistor is sized according with:
30
U: ≤ I
CWX Yb
J (eq. 2.3 [17])
Where:
8\] Line to neutral system voltage; Bc Desired ground fault current
Figure 2.8 (basic scheme for low resistance grounded system)
In presence of a low resistant grounded scheme, the effects from the system source impedance and the charging current affect the ground current value less than 0.5% in the typical range of utility supplied systems, this fact allow to neglect this two effects in sizing the ground fault resistance value. This method may provide the immediate and selective clearing of a grounded circuit, it is required that the minimum ground fault current be large enough to positively actuate the ground fault relay [17].
The sensibility of this method can be affect when is presented a fault resistance since this element reduce the ground fault current.
General comments of resistance grounding systems Networks grounded by means of resistances (low or high values) have to use surge arrester acceptable to be used on ungrounded systems. The ratings of the surge arrester (metal-oxide type) have to be sized so that neither the maximum continuous operating voltage capability nor the one second temporary overvoltages capability is exceeded under the event of one phase to ground fault [17]. This criteria should be taken into account when there is an intention to change the neutral method from solid grounded towards a resistance neutral method.
31
2.4.
Impedance grounded medium voltage networks, Petersen coil approach
The impedance grounding method is based on a current limiting impedance, which is connecting the neutral of the medium voltage side of the power transformer (located at primary substation) to the ground by means of reactance in parallel with a resistance, this method is also known as resonant grounded (or compensated grounded), since the reactive element of the impedance produce a reactive current that may be equal or approximate to the capacitive current of the system [22].
Therefore, the imaginary component of the one phase to ground fault current is decreased or eliminated, depending on the reactive current produced by the reactive component of the impedance, the ground fault current is reduced to a small resistive component which is function of the value of the fault resistance and resistance component of the current limiting impedance [24].
The basic scheme of the compensated grounded method is presented in the figure 2.9.
Figure 2.9 (basic scheme for compensated grounded system)
The reactance
:
is better known as Petersen Coil (PC), the degree of compensation can be modified when
the inductance of the PC is controllable. In this way the compensator reactance (PC) is able to follow the changes that may present in the network. In case that the value of the reactance is fixed, the compensation of the network is also fixed. The compensation degree (or tuning rate) is defined as [25]: Y
^ = YW (eq. 2.4) d
Where:
B\ Inductive current coming from the reactance
BM Capacitive current of the system
:
32
The sequence circuit of the network in consideration (under a one phase to ground fault condition) will provide the equations for the residual current measured for the healthy and the faulty feeders, the residual voltage in the MV bus bar at primary substation and the earth fault current, figure 2.10 presents the steps to obtain a reduced model of the sequence circuit of the network shown in the figure 2.9.
Figure 2.10 (a) Sequence Circuit of the network b) Reduction of sequence circuit)
The series reactance of the feeders have been neglected since are considered much lower than the feeder capacitance impedance. Additionally in fig 2.10 a) are presented the series reactance of the network equivalent and transformer, in fig 2.10 b) these reactance have been suppressed by the same reason concerning the series reactance of the feeder. The figure 2.10 b) shows that for the negative sequence circuit the capacitance of the feeder ( (
eMA , eM ) are short-circuited, the capacitances belonging to the positive sequence circuit
.MA , .M ) might be suppressed since are in parallel with the voltage source of the network.
The considerations above mentioned have been considered to reduce the model and the calculations to obtain the mathematical expression for ground fault current and the overvoltages generated in the healthy phases of the feeders.
The final sequence circuit is presented in the figure 2.11, the graph indicates zero sequences quantities that will allow to obtain the residual magnitudes in the CT of the healthy and faulty feeders, the residual voltages of the networks which is obtained by open delta VT is obtained from the zero sequence voltage Vo. These magnitudes are used to set the neutral directional protection scheme, in particular utilities like Enel Distribuzione has created a successful distribution system protection based in the neutral directional protection complementing with the utilization of the compensation impedance (Petersen coil plus resistance) [23].
33
Figure 2.11 (Reduced sequence circuit of the network)
The fault resistance of the fault is taken in consideration in order to obtain a realist approach for the ground fault current. The cero sequence impedance gS of the network correspond to the parallel of the capacitance of the faulty and healthy feeders with the contribution of the compensation impedance g: (Petersen coil resistance U: in parallel). The expression obtained for gS is the following: iX
gh =
"jklMm in
:
and
(eq. 2.5)
Where:
@o Zero sequence capacitance of the system (@o = @A + @ ) Once obtained the zero sequence impedance of the network this is added to the series fault resistance, the zero sequence ground fault current is calculated as follow:
B
o
=
B =
Cp "jklMm in !
qin j E "jklMm in !r Cp "jklMm in !
qin j E "jklMm in !r
The residual voltage
8
(eq. 2.6)
(eq. 2.7 one phase to ground current)
is obtained from eq. 2.5 and eq. 2.6 and is measured by the residual voltage
transformer connected in the MV bus bar of the primary substations.
8
8
8
= 38o = 89 + 8; + 8
= 3 × gh × −B o !
=
iX ×Cp
in j E "jklMm in !
(eq. 2.8)
34
The current measured by the residual CT in the healthy and the faulty feeders are the following:
8S `A
B
A o
=
B
A o
= 8S ×
B
B
A o A
B 3×B
× 3 = 8S ×
=8 o
@A
×
= −t o
@A
@A × 3 = B
A
(eq. 2.9 residual current in the healthy feeder)
8S 8S + u ` A 3g:
= −3 × t
8S 8S + u ` A 3g:
1 1 + u ` A 3g:
B
= −3 × 8S t
B
= −8
t
@A +
B
= −8
I
@o − @ ! +
1 u 3g:
" J in
(eq. 2.10 residual current in the faulty feeder)
According with eq. 2.8 the residual voltage 8 resistance fault the magnitude of the 8
is dependent of the fault resistance, therefore, in case of high
might decrease in such a way that the residual VT could produce an
erroneous measurement, it is necessary that residual VT should be designed to measure low values of 8
.
Once defined the residual voltages, residual current for the healthy and faulty feeders it can be constructed the phasor diagram of theses magnitudes for full compensation and under compensation. Figure 2.12 shows the two cases of compensation by means of the Peterson coil in parallel with the resistance of the distribution network presented in figure 2.9.
Figure 2.12 (a) Full compensation b) Under compensation)
35
Distribution system operators like Enel Distribuzione uses the compensated system (Petersen Coil in parallel with a resistances) with a series resistance in order to limit the time constant independently from the fault resistance and from the primary substation earthing resistance [26].
2.5.
Insulation coordination and surge arrester considerations
As seen in the previous sections, the magnitudes of one phase to ground fault current and the overvoltages produced in the healthy lines depend on the neutral method used in the power transformer at the primary substations. Meanwhile, the magnitude of the earth fault current, the residual voltage at the MV bus bar of the primary substation and the residual currents in the health and faulty feeders are used for protection scheme purposes (overcurrent or directional approach), the magnitudes of overvoltages produced by the ground fault are necessary to calculate and size the parameter of the surge arrester that should protect the several equipment connected in the distribution network. The surge arrester is an essential component to reach the goals of the insulation coordination in transmission and distribution system [28].
The coordination of the insulation is defined as the selection of the dielectric strength of equipment in relation to the voltages that can appear on the network for which the equipment is intended and taking into account the service environment and the features of the available protection devices [27].
Before to determinate the insulation level of the electrical equipment and to calculate the surge arrester characteristics, it is compulsory to take into consideration four facets of the voltages that will appear in the electrical network, these facets are the following [29]: •
Fast-front overvoltages, caused by lightning discharges with duration of microseconds
•
Slow-front overvoltages, caused by switching operations and duration of milliseconds
•
Temporary overvoltages, generally produced by one phase to ground faults which may last seconds
•
Highest system voltages, it is considered to operate in a continuous condition
The surge arrester should limit the effects of the fast-front and slow-front overvoltages, which can cause irreparable damage to the equipment insulation. For temporary overvoltages and operation condition with the highest system voltages, the surge arrester should withstand these two conditions without perform any operation. Figure 2.13 shows the voltages that may appear in the network, the surge arrester respond and the withstand voltage of an equipment.
36
Figure 2.13 (Schematic representation of insulation coordination of equipment [29])
The voltage magnitude appear in per-unit of the peak value of the highest continuous phase to earth voltage vw
1 ). ?. =
√3 √
vw !. In can be observed that voltages limited by arrester in case of fast-front and
slow-front overvoltages is below the withstand voltage of equipment (insulation level). In the other hand, the surge arrester withstand curve is above for temporary overvoltages (TOV) and the highest system voltage values as shown in figure 2.13.
The surge arrester has two important parameters necessary to develop the insulation coordination, these parameters are based on the maximum voltage in the network for continuous operation and the temporary overvoltages, the parameter are the followings [31]: • •
vM Continuous operating voltage of an arrester
v
Rated voltage of an arrester
The calculation of vM and v are highly depended on the neutral method of the network, hence there are different considerations to set the values of vM and v
for solid grounded and isolated grounded (or
compensated) networks. The selection of the continuous operating voltage vM is based on the value of the highest voltage of the network vw )ℎ_x( ` )ℎ_x( y_a?(! as follow [29]:
vM,z : ≥ 1.05 × vM,z : ≥ vw
}~ √
(eq. 2.11 Solid earthed neutral networks) (eq. 2.12 Isolated or compensated neutral networks)
37
In isolated (or compensated) networks the one phase to ground faults produce an overvoltages in the healthy
phases which reach a value of the phase to phase voltage (this means an earth fault factor , = 1.73). Once
calculated the minimally required continuous operation voltage vM,z : is determined the rated voltage v " as follow [29]:
v
"
≥ 1.25 × 1.05 ×
v
3
≥
v
"
≥ 1.25 × vw
}€m•
}~ √
€m•
(eq. 2.13 Solid earthed neutral networks)
(eq. 2.14 Solid earthed neutral networks-second approach) (eq. 2.15 Isolated or compensated neutral networks)
Solid earthed system allow a second approach to calculate the rated voltage v . The value ,Qo‚ is obtained
from U-t characteristic of the arrester taking in consideration the time duration of the temporary overvoltage
vQo‚ in case of be know. For example, if the vQo‚ elapses for one second, this voltage value (see figure 2.14)
correspond to 1.15 times the rated voltage v , this means that the rated voltages v 3 is equal to the temporary
overvoltages vQo‚ divided by the factor ,Qo‚ . In case that no information is available about the temporary overvoltages, an earth fault factor of 1.4 and a time of ten seconds should be chosen for the vQo‚ [29].
Figure 2.14 (U-t characteristic of the arrester [29]) The final value of the rated voltage is chosen from the maximum between v " and vƒ2 , rounded up to a value
divisible by three. In case that the rated voltage v 3 is greater than v " , the continuous operating voltage vM have to be calculated again as follow: }
„ vM ≥ ".3… (eq. 2.16 Redefinition of Uc)
The modification on the neutral method used in an electrical network obligates to verify the parameters of the arrester connect in the system since the nature of the overvoltages is a decisive factor to determinate the parameter of the arrester.
38
3. Modification on the grounding method in Distribution Networks.
The purpose of this chapter is presenting the main reasons and justifications to modify the grounding method in distribution network, to show aspects relating to the support infrastructure to do the changes in the network and to introduce two cases where distribution system operator (DSO) have made modification in the grounding method. DSO have changed from insulated grounded (Italian case) and solid grounded (Brazilian case) towards a compensated grounded method.
The grounding method used in distribution utility is one of the first decision in the engineering and planning stage of the network. According with this selection, the protection schemes and insulation level of the network is designed and sized. In the past decades, the DSO took their choice of a certain grounding method based on technical and economic considerations, giving specific importance to power supply quality and safety issues according to the requirements of that time period. Once chosen the grounding method, it is a very expensive and complex task to develop modifications in the grounding scheme of the system. However, exist legal and technological reasons that allow to make a re-engineering in the grounded method of the DSO [32].
Distribution networks surveys indicate that the one phase to ground fault is the most common abnormal condition that can be present in the DN [30], the grounding method has a direct effect in the resultant ground fault in terms of current and voltage. In this regard, the magnitude of the current and the voltage for ground faults have to be studied.
3.1. Motivations for changing the grounding method Engineering activities imply technical and economic considerations which find to solve particular problems. In these sense, some DSO’s have begun the process to change towards other grounded methods in order to solve specific problems regarding the operation of their distribution system under abnormal conditions, since the grounded method have no affection in normal operating conditions of the distribution network. Among the main reason that search the DSO to change the grounded method, the followings can be mentioned as the most important [32]: •
Safety issues relating to the network and security of people
•
Improvements in the Quality of Service (QoS)
3.1.1.
Safety issues
According with the grounding method chosen, the magnitude of the ground fault current range from thousands to tens of amperes. The ground fault current has a direct affectation on the energy released and the contact voltage in the site where the fault occurs.
39
Energy released: A reduction in the magnitude of the ground fault current implies a considerable decrease in the energy released for a ground fault event since the energy is the square of the ground fault current and
proportional to the time duration of the fault (B 3 × ). Even in the case that the protection system takes some seconds to clear a fault, a reduction of current has more importance in reducing the destructive energy produced by the ground fault, therefore the risk associated with the fault is decreased by means of grounding methods that reduce the magnitude of ground faults.
Contact Voltages: In general terms, the contact voltage produced due to occurrence of a ground fault is defined as the product of the ground fault current magnitude by the resistance of the earth plant, therefore, if one of these values is reduced, the contact voltage decreases. In this way is obtained an improvement in the safety of the electrical installations.
Standard such as CEI 11-1 defines the permissible contact voltage for electric installations greater than 1 kV as a function of the time (see figure 3.1). The permissible contact voltage has to be greater than the calculated contact voltage in order to reach a secure condition. Reduction in the ground fault current magnitude by means of a compensated grounded system contributes with the enhancement in safety for installations and public in general.
Figure 3.1 (Permissible Contact voltage values [33])
3.1.2.
Quality of Service
IEC 60050 defines the quality of service as the collective effect of service performances which determine the degree of satisfaction of a user of the service [1]. General speaking, the quality of service and performance of distribution networks are evaluated in terms of freedom from interruptions and maintenance of satisfactory voltages levels within limits appropriate for this type of service [34].
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Authors such as A. Pansini states that the operations related with the enhancement of quality of service include the following measures to [35]:
•
Isolate faults and restore service of the healthy portion of the distribution network
•
Transfer loads between phases or among circuit to avoid overloads or potential overloads, and improve voltage conditions
•
Switch on and off capacitors installed on the feeders and within the primary substation in order to improve the power factor
•
Permit that sections of the distribution network and sections of the primary substations, to be deenergized for maintenance and construction activities which should not affect the remaining sections of the installations.
The quality of service in distribution networks is surveyed by means of indices to evaluate the performance of the network. The most used indices (statistical indicators) and definitions are defined by the standard IEEE 1366 [36]:
SAIFI: The system average interruption frequency index (SAIFI) indicates how often the average customer experiences a sustained interruption of the service over a predefined period of time, is given by the following mathematical expression:
†‡BˆB =
∑ #h#‰\ ]}2 V hN M}w#h2V w Y]#V } #VŠ #h#‰\ ]}2 V hN M}w#h2V w wV CVŠ
†‡BˆB =
(eq. 3.1 SAIFI)
∑‹ ‹#
Where:
‹
‹#
Number of interrupted customers for each sustained interruption event during the reporting period Total number of customers served for the area
SAIDI: The system average interruption duration index (SAIDI) indicates the total duration of interruption for the average customer during a predefined period of time. Generally, it is measured in minutes or hours of interruption, is given by the following mathematical expression:
†‡BŒB =
∑ M}w#h2V 2Y]}#Vw hN Y]#V } #Yh] #h#‰\ ]}2 V hN M}w#h2V w wV CVŠ
†‡BŒB =
(eq. 3.2 SAIDI)
∑ƒ ׋ @•B = ‹# ‹# 41
Where:
ƒ
@•B
Restoration time for each interruption event Customer minutes of interruption
CAIDI: The customer average interruption index (CAIDI) represents the average time required to restore the service in the network, is given by the following mathematical expression:
∑ M}w#h2V 2Y]}#Vw hN Y]#V } #Yh] w‰YŠY = V hN M}w#h2V w Y]#V } #VŠ w‰YNY
@‡BŒB = ∑ #h#‰\ ]}2
(eq. 3.3 CAIDI)
MAIFI: The momentary average interruption frequency index (MAIFI) represents the average frequency of momentary interruptions, is given by the following mathematical expression:
•‡BˆB =
∑ #h#‰\ ]}2 V hN M}w#h2V w 2h2V]#‰ Ž Y]#V #h#‰\ ]}2 V hN M}w#h2V w wV CVŠ
•‡BˆB =
} #Yh]w
(eq. 3.4 MAIFI)
∑ B• × ‹z ‹#
Where:
B•
‹z
Number of momentary interruptions Number of interrupted customers for each momentary interruption event during the reporting period
Major event: Defines an event that surpass reasonable design and/or operational thresholds of the electrical network.
3.1.3.
Service quality regulation: General concepts
DSO’s develop several improvement and reinforcements in their networks in order to obtain better conditions regarding the safety of the distribution system under faults and quality of service enhancements. This is the case of AES Sul, a Brazilian DSO that has introduced a change on the grounded method of the medium voltage system, AES Sul is moving from a solid grounded towards a resonant grounding method. By means of this grounding method, the ground fault decrease down below to their self-extinguish current, the great percentages of these events does not cause outage in the system and not disturb the costumer supply [37].
For the above mentioned case, there are not externals motivations that compels it to make reinforcements of the networks, besides of pursuit of improvement of safety issues and quality of service. By other hand, DSO might be compelled to guarantee a minimum quality of service performance in case of existence of legal framework that obligates to DSO to reach the goals stated by regulatory agencies.
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Many countries around the world have started a liberalization process in their electrical system. This process is accompanied with privatization (not always), market opening and freedom of choice in the network services. Therefore, it is expected that a liberalized system is able to offer better services with decreased cost, in this way there will be an approval from consumers, which is a requirement to attract investment in order to guarantee the condition for lasting security of supply and the reinforcements and enhancement in quality and efficiency [38].
The service quality for the distribution networks evaluates three main areas, which considerer technical (continuity of supply and voltage quality) and non-technical aspect (commercial quality), these areas are generally regulated, and detailed as follow [38]:
•
Commercial quality: The area regarding commercial quality evaluates the non-technical issues about the relationship between distribution companies and the customer, before the beginning of the service and during the contractual times. It also cover the quality of services regarding the provisions for new connections into the network, meter reading, billing, and management of customer request and complaints. It is necessary to make a differentiation between services provided before the supply of electricity star and those provided during the contract, in table 1 it is indicated a list of the most common services.
Table 1 (Regulated service, frequently applied [38])
The indicator that .depict the non-technical quality of service is the time between the user request and the provision of the service, also named as waiting time.
•
Continuity of supply: Correspond to a technical area related to interruptions of supply. Continuity of supply mainly focus on the events where the voltage at a user connection falls to zero, it is described by two quality dimensions: the number of interruptions and their duration. Hence, the regulatory parameters are concentrated on indicators of frequency and duration of interruptions. Therefore, the target of regulatory instructions and data collection support is to assemble reliable information that help to describe the performance of the distribution network regarding to the number and duration of supply interruptions.
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The most common used statistical indicators of performance are: average number of interruption per customer per year (SAIFI), average interruption duration per customer per year (SAIDI) and energy not supplied. The distribution company should have the necessary infrastructure to measure and register the events regarding to the interruption of services, specifically the DSO need to have a SCADA to process and storage the information associated with the interruption of service.
The regulation of continuity of supply are accompanied with a reward and penalty schemes, which are complex tools that regulator authorities apply to system-level indicators in order to persuade the regulated DSO to generate desirable levels of service quality. Reward and penalty policies constitute an incentive scheme that modify the DSO revenues depending on its performance against performance standards elaborated by the regulator authority. The reward and penalty schemes are conceived as mechanism to guarantee that acceptable level of service quality are delivered to the users. The implementation of this regulatory tool is also motivated by the necessity to counterbalance the potential risk of quality degradation related to the adoption of price cap regulation with respect to privatization process of the DSO. Figure 3.2 represents the basic functional relation between revenues and quality, it is a continuous linear function. According with this scheme, a different financial stimulus (reward or penalty) correspond to each level of quality provided by the DSO.
Figure 3.2 (Reward-Penalty linear incentive scheme [38])
•
Voltage quality: Evaluates a subset of the possible variations of the voltage characteristics from its ideal waveform, the deviations of the voltage can produce damage or malfunctioning to the electrical equipment of customers. As examples of these variations are voltages dips, voltage harmonic and flicker. The quality dimensions that are important for the users correspond to the number of such deviations in a period of time or the amplitude of the deviations, to mention an example. Thus, the regulator authority focus on indices such as frequency of the events. Voltage quality is a very specific and technical topic, many of the issues regarding to it are already covered by technical norms that define the voltage characteristic of the electrical energy supplied by DSO. In Europe, the main reference for voltage quality is the European Norm EN 50160. Another important norm is the IEC 61000 series on electromagnetic compatibility. The above mentioned norms concern voltage disturbances, immunity and emissions from electrical equipment and presents measurement techniques for voltage quality characteristic. It is worth to mention that many Europeans regulators consider that the EN 50160 is not completely satisfactory for customer protection, nowadays only a reduced number of countries in Europe use voltage quality regulation.
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3.1.4.
Service quality regulation: Italian case
Since the beginning of millennia, there have been remarkable changes in the European power sector, including the Distribution companies. Countries like Italy has launched reforms in the law in order to liberalize the electricity market, the reforms include the privatization of the largest electrical energy operator (Enel), besides, has been created a regulation and control agency (Autorita per l’Energia Elettrica e il Gas - AEEG).
The authority rules are in force since January the 1st 2000, and according with these new rules, the DSOs are subjected to a regulation system of the continuity of electricity supply and distribution tariffs with a regulatory period of 4 years. The regulation of continuity of supply establish indices (SAIDI, SAIFI, and MAIFI), rules to measure (weighting methods, duration calculation), rules to classify (type, cause, and origin), geographical classification (high, medium and low concentration districts), additionally, a progressively challenging incentive scheme based on [39]:
•
Since 2000, SAIDI reduction
•
Since 2006, max number of long interruptions for MV users
•
Since 2008, SAIDI, SAIFI and MAIFI diminution
•
Since 2009, very long interruptions decrease
Since the introduction of the new regulation frameworks, Enel Distribuzione changed the previous scheme for quality enhancements, which was based on a long term plant of network replacement, principally to decrease the number of interruption in the system. The new approach of Enel has been based on an integration of technical and organizational interventions. The main projects (performed during the first regulation period) oriented to decrease the average number of interruption are the followings [40]:
•
A new planning principles applied to the maintenance interventions on the distribution network, which is based on “weak signals”, such the frequency of interruptions shorter than 3 minutes, instead of a “time base” approach (frequency of inspections per year).
•
Implementation of MV network configurations more reliable by means of the construction of HV/MV substations in order to decrease the average length of MV lines.
•
Renovation of MV bare aerial network through an extensive replacement of insulators and conductors.
•
Replacement of MV bare conductors with insulated cables: overhead cables in highly wooded areas, underground cables mainly in rural areas
•
Introduction of the Petersen Coil in HV/MV substations in order to obtain a compensated grounded distribution network. This project has begun in fall 2001, the wide installation of Petersen Coil could be considered the fundamental component of the strategy oriented to decrease the number of short and long interruptions.
•
The remote control of the switchgears in MV/LV substations aimed to reduce the indices regarding the average duration of the single interruption, which has resulted to be the key project to reach a considerable reduction of this index. The main features of the features of the system are: motorized onload switch in MV/LV substations (3 or 4 for each MV feeder), low cost/high performance Remote Terminal
45
Units (RTU), telecom modules based on GSM system, and 29 control centers for all the Italian territory. The main goal of this project was to remotely control 80000 secondary substations within the year 2004.
In table 2 is presented the main components of the strategy for quality improvement developed until the year 2003.
Table 2 (Main projects to improve the QoS - first regulatory period [40])
Since the introduction of regulations for quality of service, Enel has decreased the SAIDI index considerably, (see figure 3.3). According to the incentive scheme released by the regulator authority (AEEG), each DSO in charge of specific reginal areas is assigned with target performance levels of the distribution network which generates premiums or penalties (incentives scheme) for meeting or failing to reach the purposed targets. By means of this incentives approach and the enhancements in the distribution network, Enel’s premium balance for the 2000-2007 period was roughly €876 M. As seen in figure 3.3, in the first period regulation (2000-2003) the reduction in the SAIDI is equal to 69 minutes, meanwhile for the second regulation period was 23 minutes. The more important projects that supported the reduction in SAIDI were remote control of secondary substation (MV/LV substations) and automation of the medium voltage network. [39].
Figure 3.3 (Quality of service improvement - SAIDI index reduction [39])
At the year 2010 is registered a SAIDI value of 46 minutes, and a quantity near to 20000 MV feeders include at least one automated MV/LV substation which help to obtain the results in terms of cumulative duration of short and long interruption to the users. Since the update policies of the Regulator, not only the cumulative interruption time (duration of long and short interruption) is taken in consideration, but also the total number of supply interruptions (long, short and transient) have to be decreased. The aforementioned new requirements form the Regulator constitute a driven force to develop new project that improve the network and reach the goals established by the Regulator [53].
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3.2. Improvements in the distribution network under the Smart Grid approach In many countries of the EU, the enhancements of the distribution network infrastructure is aimed by the quality of service regulation. In the case of Italy, the regulation policies considerer three complementary aspects: grid technology innovation, new grid services, and grid user participation [45].
Besides the quality of service motivations, the growth in distribution generation (DG) of the renewable energy sources (RES) requires several modifications in the infrastructure and practices in the distribution networks. Additionally, exist other reasons and needs that drive the modernization of the electrical systems, in the case of EU the following motives are mentioned as follow [46]:
•
User centric approach, since the increased interest flexible demand for energy, lower prices, microgeneration opportunities, valued added services and electricity market opportunities.
•
Security of supply, since the limited primary resources of traditional energy sources it is necessary a flexible storage, a higher reliability, and to increase network and generation capacity.
•
Liberalized market, the electrical networks should respond to the requirements and opportunities of liberalization by creating and allowing both new products and new services.
•
Interoperability of European electricity networks, it is necessary to support the efficient management of cross border and transit network congestion, to improve the long distance transport and integration of RES and to strength the European security of supply by means of enhanced transfer capabilities.
•
Central generation, this face implies the renewal of the existing power plants, development of efficiency improvements and the integration with RES and DG.
•
Environmental issues, this means reaching the Kyoto Protocol targets, reduction of the losses in the system, increasing social responsibility, and sustainability.
•
Demand response and demand side management, it is required to develop strategies for local demand modulation and load control by electronic metering and automation meter management systems.
•
Politics and regulatory aspects, this issue regard to the continuing development and harmonization of policies and frameworks in the EU context.
3.2.1.
Definition of Smart Grid and conceptual model
The necessity of change represents a great opportunity to modernize the electrical infrastructure (generation, transmission, distribution and consumption). In order to reach the several targets of the modernization of the electrical networks, it is implement a new concept to face this challenges, the Smart Grid approach.
The relative new concept of Smart Grid (SG) is highly used as a marketing term, however, exists a formal definition stated by IEC. According to IEC, the SG refers to the electrical power system that employs information exchange and control technologies, distributed computing and associated sensors and actuators, for goals such as: integrating the behavior and actions of the network users and stakeholders, to deliver sustainable, economic and secure electricity supplies [1].
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Authors such as E. Hossain et al [41] conceive the SG as the next-generation electrical power network to supply reliable, efficient, secure and quality energy (generation/distribution/consumption) using modern information, communications, and electronic technology. The SG will provide a distributed and user-centric system that will include end-consumers into its decision processes to implement a cost-effective and reliable energy supply.
The Smart grids European Technologic Platform provides documents that define the concept of SG as follow: “A Smart Grid is an electricity network that can intelligently integrate the actions of all users connected to it – generators, consumers and those that do both – in order to efficiently deliver sustainable economic and secure electricity supplies” [43].
The survey developed by X. Fang et al asserts that the initial concept of SG began with the idea of advanced metering infrastructure (AMI) with the objective of enhance the demand-side management, energy efficiency and construct a self-healing reliable grid protection against malicious sabotage and unforeseen event (i.e. natural disasters). Nevertheless, the new necessities thrust the electrical sectors, research institutions, and governments to reconsider and expand the initially perceived scope of SG, in this sense, the U.S. Energy Independence and Security Act of 2007 directed the National Institute (NIST) to coordinate the research and development of a framework to achieve interoperability of SG systems and devices [44]. In accordance with the report for NIST [47], the benefits of the SG approach are mentioned as follow:
•
Improvements in power reliability and quality
•
Optimization of facility utilization and deferring the construction of peak load power plants
•
Enhancements in capacity and efficient of existing power networks
•
Improving resilience to interruptions
•
Facilitating expanded deployments of RES meanly in distribution networks
•
Automating maintenance and operations, enabling predictive maintenance and self-healing responses to system perturbations
•
Reduction in greenhouse gas emissions by means of electric vehicles and RES
•
Allowing the transition to plug-in electric vehicles and new energy storage facilities.
In figure 3.4 is depicted the conceptual model provided by NIST in order to develop a SG approach in the electrical networks. The conceptual model divides the SG into seven domains, each domain spans one or more SG actors, including devices, system or programs that make decisions and exchange information necessary to perform applications, it can be noted that the communication flows constitute a very important component of the conceptual model, the implementation of integrated communications is a key factor to create a dynamic and interactive infrastructure. The NIST has proposed this model from the perspectives of the different roles involved in the SG. A compressed description of the actors and domains are provided in the table 3 [44, 47].
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Figure 3.4 (NIST - SG Conceptual Model [47])
Table 3 (Domains and Actors in the SG conceptual model [47])
The SG approach provides considerable benefits for the modernization of the electrical system, however, the introduction of SG implies in many case the introduction of power electric that can affect the fundamental voltage waveforms by introducing harmonics, additionally the allocation of DG in the distribution networks may present some problems regarding voltage control, inverse power flow and discoordination in the protection schemes, therefore, it is necessary to perform studies towards quantifying the impacts of SG applications on the power quality of the network [42].
3.2.2.
The role of communication infrastructures in Smart Grid
The SG is considered as a network composed by many system and subsystem interconnected among them in order to offer cost effective and reliable energy supply for an increasing demand. Furthermore, a smart grid will be accomplished by overlaying the communication infrastructure with the electrical network infrastructure.
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An advanced communication techniques and protocols support the improvements in the reliability, security, interoperability, and efficient of the electrical network. Additionally, to reach a high level of connectivity and interoperability, it is required open system architectures as an integration platform, shared technical standards and protocols, and information system to operate in an efficient way the considerable quantity of smart devices and systems. As a matter of fact, a smart grid may include many systems architectures developed independently or by means of the association with other system [41, 47].
Figure 3.5 presents a hierarchical overview of the smart grid scope, its relation to NIST domains, and examples of associated components and technologies. Form a theoretical point of view, each domains, components, and technologies would communicate with each other in order to offer any of the SG goals [41, 48].
Figure 3.5 (Hierarchical overview of SG communication infrastructure [41])
The communication and interactions among the several components (depicted in figure 3.5) can be reached by means of Advanced Metering Infrastructure (AMI), which performs as the gateway for access , allowing the bi-directional flow of information and power to support the allocation of RES in the distribution network (i.e. the DG in the MV distribution network). AMI is required to provide near real-time metering data (including fault and outage) to the utility control center. To do that, the smart meters have to be an integral component of AMI, which should support efficient outage management, customer billing and demand respond for load control. AMI might include a hierarchical network or a multi-tier architecture with mesh or star topologies, and different communication technologies such as power line communication (e.g. broadband over power line BPL), cellular network (e.g. CDMA or GSM), wireless technologies (e.g. Wi-Fi, ZigBee, WiMAX), and networks based on Internet Protocol (IP). AMI includes local data aggregators units (DAU) to relay and collect the information from the smart meter (SM) to the meter data-management system (MDMS). MDMS provides storage, management, and processing of meter data to be used in power system applications and services.
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Additionally, many networks and subnetworks such as wide-area measurement systems (WAMS), sensor and actuator networks (SANET) can be grouped under a hierarchical framework based on wide area networks (WAN), neighborhood area networks (NAN) and home area networks (HAN) [41].
Since the SG will be constitute by several communication networks and system, its need to be an interoperable system. This property becomes a remarkable issue because enable the infrastructure and information to come together into an integrated system for information to be exchanged without user intervention.
According with the approach developed by the Grid Wise Architecture Council (GWAC), the most important interoperability issues of a communication networks are the following [41, 49]: shared meaning of content, resource identification, plug and play, time synchronization and sequencing, security and privacy, quality of services, and scalability
In order to face the requirements to build a SG, exist a wide range of enabling technologies in areas such as integrated communications, sensing and measurement, advanced component, advanced control, and improved interface and decision support have to be put in operation. It is important to remark that among the technological area previously mentioned, the construction of integrated communications constitute a driving factor to create a dynamic and interactive infrastructure to integrate all upstream (towards the generator) and downstream (toward the user) elements to operate in a unified fashion. In figure 3.6 it can be observed a complete communication network infrastructure of SG indicating the communication core network and last mile connection [41].
Figure 3.6 (Overall communication infrastructure of SG [41])
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3.2.3.
The Standard IEC 61850
Since the interoperability is a key factor for communication networks in a SG context, it is worthy to mention one of the most used and remarkable communication protocol: the IEC 61850 standard. The first edition of IEC 61850 was launched in 2003 and was created to deal just with the substation automation, after that, the second edition was extended, the name of the standard is IEC 61850 Communication networks and systems in substation. The principal goal of IEC 61850 is to reach the interoperability among Intelligent Electronic Devices (IED), which are used for controlling, monitoring and protection functionalities from different suppliers by defining: a common model to describe the information that can be exchanged, a group of services acting on that information, and some protocol to perform the exchange of information [50].
The reference model of IEC 61850 (depicted in figure 3.7) constitutes the base of the flexibility required in communication protocols involved in a SG context. The key characteristic is to separate the solutions with features of long term stability on one hand and the fast changing communication technologies on the other hand. Therefore, the main applications of the network operations will be maintain stable in the future. Meanwhile, a rapid advancement can be obtained from the information and communication technologies. As a consequence, the reference model of the standard IEC 61850 is created to offer: the required stable foundations for basic applications, and high flexibility concerning the application of new communication technologies [51].
Figure 3.7 (IEC 61850 Reference Model [51])
Concerning figure 3.7, the applications to control the network need the definition of data objects including their modeling and the communication services, IEC 61850 defines these data objects within the abstract communication services interface ACSI. The specific communication service mapping SCSM allow to combine the data model and service of the ACSI with the up to date communications technologies (seven layer protocol stack OSI model). The IEC 61850 standard supports a general system approach by linking the practice of electrical system operations with the communication architecture [51].
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The structure of communication services of IEC 61850 standard provides two communication ways of exchange for information, the client-server and the publisher-subscriber principle. The publisher-subscriber principle has two variants, the multicast of urgent messages by means of the GOOSE mechanism (Generic Object Oriented Substation Event) and the transfer of sampled values (SV).
Figure 3.8 (IEC 61850 Protocol Stack)
The client-server approach is applied for substation automation system (SAS) applications such as control and supervision of substation equipment, data requests, event report transmissions, time synchronization, storing and retrieving sequences of events (log), and transfer of files (Comtrade files). The client-server approach utilizes sequences of information exchanged with confirmation messages in order to guarantee that the data is received by the IED using a TCP/IP addressing scheme. The GOOSE approach is used for time critical information exchanges (fast transmission within milliseconds), in this scheme one IED acts as a publisher giving the exchange of urgent information after the occurrences of a configured event, it is used a multicast transmission, the transmission of the event message (GOOSE message) has the highest priority and is received by the subscriber defined in the engineering stage. The sample values (SV) are more concerned with analogous values measured by the merger unit (MU) [51].
3.2.4.
Smart Grid projects in Italian Distribution Networks.
The introduction of the DG and the quality of service regulation in the electrical industry (utilities companies) have thrusted several projects to overcome the problems associated with the allocation of the DG in the distribution network and reaching the targets imposed by the regulation Authority. Since the beginning of the liberalization period, several projects have been carry on in order to deal with the new challenges. In this sense, the distribution system operators perform improvement in their electrical system to become from a passive networks towards an active networks, and final a smart grid system.
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DMS Concept The efforts to become the network an active network have to be supported by a Distribution Management System (DMS). DMS is term used to indicate the distributed control centres required to manage the electric network at sub transmission (high voltage) and distribution levels (medium voltage). The DMS are in charge of activities such as off-line analysis of the network, geographical information systems, work force management, outage identification and restoration, it also includes advance applications concerned to on-line control and auxiliary services provision. One of the more important task of DMS is to support the operators with reliable tools to track information not measured, the DMS requires functions that allow to detect, report, supplest feasible solutions, and estimate time of outage duration. Therefore, the main DMS functions are real time measurements, state estimation, power flow calculation, performance indexes calculation, short circuit calculation, voltage control, losses optimization, configuration switching optimization, control of local DG, control of dispatchable loads, and energy storage devices control [52].
Figure 3.9 (DMS architecture – key elements [43])
Figure 3.9 presents an example of a modern DMS architecture including the key elements such as Material World Modules (MWM), Outage Management System (OMS), Geographical Information System (GIS), Maintenance Data Management System (MDMS), Customer Information System (CIS), and Demand Side Management (DSM). It is worth to mention that DSO companies have management their grids according to four main areas (operation, maintenance, engineering, and commercial), frequently these areas generated the development of independent application software. The new trend of DMS is to design a single platform that integrates all function and applications [52].
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SDNO Project The Smart Distribution Network Operation (SDNO), developed by Enel Distribuzione (ED), was launched to support the spread of the DG in the MV network and the transition of the passive MV network towards a SG system. The project was based on the” state of the art” solutions such as the use of new grounding method using a Petersen Coil (in addition with a resistor) and automatic selection of faulted feeders without affecting the healthy ones. The SDNO project was focus in four main areas given as follow [54]:
•
HV/MV substation, focus on protection, control, and automation equipment, this include the hardware and software.
•
MV network automation, which include fault detectors, automatons and remote terminal units (RTU)
•
Communication network, covering the DG control and operation, and the remote controlled and automated MV/LV substations.
•
Main SCADA system, to be adapted to the requirements of DG.
POI-P3 Project After the SDNO project, Enel Distribuzione launched the POI-P3 (founded by the Italian Ministry of Economic Development), which proposes a new advanced management of Distributed Energy Resources (DER) to overcome the problems related to reverse power flowing, to keep the necessary levels of availability and power quality. The main areas of applications are the following [55]:
•
The communication infrastructure, which is based on a broadband “always on” technology in order to connect MV producers, passive users, main secondary substation of the MV feeders, and the primary substations.
•
New protection and control system in primary substation, using a new approach to manage the on-load tap changer of the HV/MV transformer, since the former method is not effective under the presence of DG.
•
Enhancements in hardware and software located at peripheral and central level, which are necessaries to implement control functions and data collection.
The communication system became the necessary background infrastructure that allow the exchange of information between the control system and the user (actives and passives). The Central Control System and primary substations are communicated by means of a point to point virtual connections, which use a private IP network belonged by public providers. For the links between secondary substations and their respective primary substation, a wireless communication platform is used (WiMAX or 3G), the implementation of optic fiber is used mainly to communicate the active/passive user with the secondary substation. In figure 3.10 is depicted the communication architecture. Regarding the communication protocols, the standard applied is the IEC 61850, used inside the primary substation and to communicate with equipment distributed along the MV feeders [55]. Figure 3.11 shows the general architecture of the POI-P3 projects including the main components.
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Figure 3.10 (Communication Architecture POI-P3 project [55])
Figure 3.11 (General Architecture POI-P3 project [55])
The main benefits expected for POI-P3 are the followings: increase of MV network hosting capacity (ability of the network to admit DG), reduction of greenhouse gas emissions, increase of energy efficiency, optimization of investments in network expansion, and participation of DSO in the market of ancillary service (including services related toward the TSO) [55].
InGrid Project This project is created to respond the needs of improvement in observability of the system, and to establish appropriate communication channels with the users (passive or actives). Once these activities have been carried out, it can be done a correct application of algorithms of control for the DN (e.g. voltage regulation and emergency network reconfiguration functions), and enhancements in the SCADA in order to manage the new applications and information that come from the entire network. The new group of software applications are required to support the DSO in real-time operation and in the phase of planning [56].
56
Figure 3.12 present the system architecture of the InGrid project. As can be noted, the SCADA system obtain information from the entire network by means of the RTU installed in the primary substations, secondary substations and the RTU associated with specific users. The SCADA has been improvement in such a way that has the capabilities to interact with the Network Calculation Platform (application algorithm of InGrid project) and the Load and Generation Forecast application. The innovation of the InGrid project relies in the algorithms used in the DMS, the main components are described as follow [56]:
•
Network State Estimation, the DSO needs a complete information about the configuration and stated of the network in order to develop analysis or control action, to do that, two method of state estimation are proposed: a) simplified state estimator, only measurements in the PS are known and is only possible to do estimation at the PS level, b) complete state estimator, the measurements in the SS are available, here the DN consider its complete structure. In both methods, a part of generation and load profile can be accurately known.
•
Voltage Regulation, the spread of DG allocated in the MV and LV networks present several problems regarding the current techniques for voltage control in the MV feeders (voltage profile), specifically the onload tap changer of the power transformer in the primary substation does not work with the DG, therefore it is necessary new strategies to face the new problems. The voltage regulation architecture is divided in three components: a) local control, which regulate a single generation unit, b) coordinated control, focused on the coordination of reactive power support provided by all DG in service, and c) centralized control, based on an optimized procedure to dispatch reactive power.
•
Network Configuration, used to respond the needs of the DG and the classical energy losses reduction goals, this algorithm is classified in two categories: to manage emergency situations providing a network configuration that mitigates the emerged situation (faults, contingencies), to optimize the topology of the DN with respect to performance indices.
Figure 3.12 (System Architecture InGrid project [56])
57
Enel Smart Grid Test system The new components and equipment in the enhanced Italian distribution network exchange information by means of the protocol IEC 61850 in an always on communication network. Considered that IEDs and RTUs (installed in the primary and secondary substation) constitute the main source of information to know the state of the network, these have to be tested. The Enel test system permit to test processes, algorithm, and devices under real field condition. The test system is based on the Canadian Real Time Digital Simulator (RTDS), which is based on parallel computing technology that allow electrical system to be numerically simulated in real time. The signals and messages transmitted among the equipment and the RTDS are exchanged via wired interface or via IEC 61850, additionally, the RTDS also permit to simulate IEDSs (i.e. IRE). These important characteristic allow to connect real IEDs and RTUs to a simulated grid in order to obtain a completesafe real-time SG “Hardware in the loop” test system, this platform is very useful to simulate future scenarios before any operation in the real network, beside the test system allow a pre-tuning of IEDs or other devices. Devices such as the Petersen Coil regulator and the tap changer regulator can be tested by RTDS test system. In figure 3.13 is depicted the logical scheme of the RTDS test system, the IEDs and RTUs functionalities will be mentioned in the next sections. [57].
Figure 3.13 (RTDS Logical Scheme [57])
58
3.3.
A mature electrical network: Italian case of Enel Distribuzione, from insulated to compensated grounding system
In the previous sections was mentioned some reasons that drive towards a modification in the grounded method of the distribution network. The motivations may come from technical improvement aims or can be based on legal mandates released by a Regulator Authority, which set a series of performances indices to be reached by the DSO. In general a regulator establish a police of quality regulation in the electrical industry, in this sense, the distribution companies have to develop great efforts to enhance their network in order to reach the goals of the service quality regulation.
In the case of Italy, the quality service regulation constitute the main driving force to execute the reinforcements in the network, thus, it will be reach the goals establish by the regulator authority. In the previous section were mentioned some project aimed to improve the performance of the network, these projects are oriented to allow a greater presence of DG, to boost a more efficient communication network infrastructure (in the primary and secondary substations), to develop software application to support the DMS (i.e. InGrid project), to improve the automation process in the MV feeders regarding the response under faulty conditions with the support of protection schemes.
Concerning the automation process to responds the faults and the protection schemes associated to it, the changes in the grounding method become a fundament component of the new automation a protection approaches. The previous scheme was an insulated method in the transformer of the primary substations.
This section deal with the main components associated with the automation and protection schemes associated with the compensated grounded method used by Enel (and other Italian DSO), and is also presented the an overview of the elements that conform the primary and secondary substations in order to give a complete picture of the distribution network.
3.3.1.
Primary Substations in Enel Distribuzione, HV network considerations
In the norther regions of Italy, the HV subtransmission network mostly operates at 132kV. The HV network is configured and operated looped or meshed, including operational switching substations necessary to reduce possible overloads in the HV lines, figure 3.14 indicates a basic scheme of the HV subtransmission system.
59
Figure 3.14 (HV network scheme)
The HV/MV substation of Enel, in general, are composed of two step-down transformers, usually with the followings ratings: 2x25 MVA, 2x40 MVA, in some cases with 2x16 MVA or 2x63 MVA. Each power transformer provides a redundancy of 40-50% in normal operation conditions. The two transformers scheme per substation can provide a relative quick supply restoration in case that one of them is out of services (outages caused by faults in the transformer).
The service quality regulation requires also some considerations regarding the configuration of the HV/MV substation (primary substations) and theirs associated feeders, in this sense, Enel has considered the following aspects in order to improve the distribution network [60]:
•
Conventional HV/MV substations of compact design with two power transformers (large power rating and redundancy)
•
A simplified approach for physically small HV/MV substations with only one power transformer (ratings of 16 MVA or 25 MVA) and with a lower power redundancy capacity. Reduced quantity of short MV feeders coming from each new HV/MV substation, in the case of MV feeders that link two HV/MV substations, there will be include 5 switch disconnectors in average (the switch disconnector belongs to an automatized secondary substation). In figure 3.15 is presented a basic scheme for this approach, it is indicated a border switch which divides the feeder in normal operation conditions, this type of feeder should be size (thermal capability of the cable) accordingly to provide back up to the other section in case that its associated primary substation is out of service.
•
Introduction of MV/MV substations, these substations can be adopted in place of a new HV/MV substation, which could be constructed later on when the benefit-cost ratio justify the related investment.
60
Figure 3.15 (Primary and Secondary substation scheme)
In figure 3.16 is presented the schematic diagrams of the two HV arrangements used by Enel, for the simplified one-transformer primary substation, and the conventional “H Type” substation which have two power transformer.
Figure 3.16 (HV substation arrangements)
3.3.2.
Basic protection scheme of Primary Substation
Regarding the protection used in the primary substation, Enel uses a standardized scheme, which device the substation in three protection zones, which are the following and indicated in the figure 3.17: •
HV line protection
•
Power transformer and MV bus bar protection
•
MV feeder protection
61
Figure 3.17 (Basic protection scheme in PS)
The HV subtransmission network are meshed, therefore, each HV node (primary substation) may be supplied by two HV lines, the HV voltages lines connected to the primary substation are protected by a distance function (ANSI code 21). To correctly select the faulted HV line, it is not possible to rely on: fault current only, fault current and direction, or voltage variations. It is necessary to use the distance relays. Additionally, the protection scheme for the HV lines includes a reclosing cycle to extinguish the fault in case of an intermitted fault (ANSI code 79). For the protection of the power transformer, the protection scheme is performed by two protection equipment, DV920, and DV925:
a) HV Side power transformer (equipment DV920), which have the following functions: •
Overcurrent relay, 1st threshold: 3.5 x B"# and t=0.8 s for TR ≤ 25 MVA (B"# = thermal current primary side)
• •
Overcurrent relay, 1st threshold: 3 x B"# and t=0.6 s for TR ≥ 40 MVA Overcurrent relay, 2nd threshold: 1.3 x B
and t=0 s (instantaneous 40ms). In case of short circuit in
the MV bus bar, seen from the HV side. •
Alarm and trip of Buchholz relay
•
Alarm and trip of maximum temperature relay
•
Alarm and trip of minimum oil level
b) MV Side power transformer (equipment DV925), with the functions: • Overcurrent relay, threshold: 1.4÷1.6 x B] and t = 1.5 s, to protect the power transformer against overload, and to allow the elimination of fault on the MV feeders as back up of MV lines relay. • Residual overvoltage relay (59N). For isolated networks, 36÷8 V secondary. For compensated networks 15÷10 V secondary.
62
Regarding the protection of the MV feeders that depart from the MV bus bar of the primary substation, the equipment DV901 perform the task of protection of the MV lines independent of the grounded method present in the network. The DV901 has the following functionalities:
•
Provides the open and close command for the MV circuit breaker of the feeder.
•
Develop the reclosing cycle apply to the automation scheme FRG and FNC (ANSI 79)
•
Perform the directional earth fault protection 67N, for insulated and compensated grounded conditions of the MV network.
•
Provides an overcurrent protection 51 for short circuits in the feeder. This protection offers three threshold, are the followings:
o 1st threshold: 1.2 x B: and t=1 s for overloads in the feeder (B: = nominal current of the feeder) o 2nd threshold: 2.7 x B: and t=0.25 s for short circuits far away from the primary substation o 3rd threshold: 4.7 x B: and t=0 s for short circuits near of the primary substation
In figure 3.18 it can be observed the protection coordination for a power transformer of 40 MVA, 20kV secondary side with 15% of short circuit impedance, the nominal current of the feeder is 300 A. In table 4 are indicated the setting of the protection equipment.
Settings
Current (A)
Overcurrent 1st Threshold 4855 HV SIDE (DV920 Protection device) Overcurrent 2nd Threshold 10020 MV SIDE Overcurrent 1st Threshold 1156 (DV925 Protection device) Overcurrent 1st Threshold 360 MV LINE Overcurrent 2nd Threshold 800 (DV901 Protection device) Overcurrent 3rd Threshold 1400 I nominal (A) 1156 I overload (A) 1618 I short-circuit MV side (A) 7707 Overcurrent setting are referred to the MV side
Time delay (sec) 0,6 0 1,5 1 0,25 0 HV/MV 20 MVA 20KV MV Side
Table 4 (settings overcurrent protection)
63
Figure 3.18 (Overcurrent Protection coordination in PS)
3.3.3.
Introduction of the Petersen Coil approach
The introduction of the Petersen Coil (in parallel with a resistor) constitute a great change regarding the operation of the system under abnormal condition (i.e. one phase to ground faults). Previously, the distribution networks operated with an insulated grounded method accompany with a monitoring system.
Even with improvements in the communication system (with an insulated grounded scheme), the new requirements established by the Regulator Authority imposed a series of indices regarding the quality of the services in the distribution network. Therefore, and according with [54, 61], the performance required by the new regulation policies cannot be reached without changing the structure of the system, this became one of the main reason of the introduction of the Petersen Coil in the primary substation.
Another reason to choose the Petersen Coil approach was based in the growing of the capacitive current in the distribution network (use of buried MV cables), since the continuous increment in the demand and users. In the early stages towards a new neutral method,
Several prototypes was launched to be tested, Enel used a tunable and fixed coils, these coils were connected to earthing transformer (Zig-Zag configuration), and to the neutral point (MV side) of the power transformer. After many test and research studies, it was concluded that the solution with an automatic tunable coils constitute the best option for big networks since the automatic tuning process of the coil allow to adapt to the change in the configuration of the distribution system. Additionally, fixed coils are used in parallel with the variable coil (tunable) in order to increase the reactive current as necessary (i.e. one power transformer feeding two MV bus bar). The results obtained from the prototypes produced the following consequence [62]:
64
•
A new digital directional relay was develop, this new approach regarding the ground fault is strictly related with the introduction of the Petersen Coil. Even more, this new relay is able to respond to both neutral methods, insulated and compensated, without any external signal that indicate the neutral method used in the system.
•
A resistor in series to the Coil is introduced in order to improve the behavior of the current transformer under saturation conditions.
•
The neutral MV bushing of the HV/MV transformer is the standard solution to connect the Petersen Coil to neutral point.
•
It was designed the neutral bus bar using single phase switch disconnectors.
Figure 3.19 presents the one line diagram of the primary substation with the switch disconnectors (LS: load switch) associated with the Petersen Coil installations, the PC is connected in MV neutral bushing of the Yyn power transformer. It can be observed the parallel resistor to the PC (tuned coil) and an additional coil with fixed value.
Figure 3.19 (Petersen Coil basic scheme [63])
The new grounding method applied in the distribution network of Enel has required the test of prototypes to study theirs performances, further requirements of the components associated with them, necessity of equipment to monitor and control the new neutral approach. In this regard, among the main issues can be mentioned the followings [62]:
•
There are two schemes under test, the connection of the PC in the neutral MV bushing of an Yyn transformer (as seen in figure 3.19), and the use of Zig-Zag earthing transformer connected in the MV busbar of the primary substation to provide a neutral point and the further connection with the PC, the scheme is shown in figure 3.20.
65
Figure 3.20 (Petersen Coil connection with Zig-Zag earthing transformer)
The connection of the PC to neutral point using an Zig-Zag earthing transformer constitute a better solution in comparison with the connection to the MV neutral bushing of a Yyn power transformer since this approach cause some problems, which are indicated in the table 5 [62].
Table 5 (comparison of grounding method of PC [62])
The use of a Zig-Zag earthing transformer needs its own MV circuit breaker connected in the MV busbar (i.e. an additional cubicle in the MV switchgear) and the respective protection device. Since the cost associated to the required cubicle and the difficulties in the upgrade of the MV switchgear (MV busbar), Enel has decided to use (as standard solution) the MV neutral bushing of the Yyn power transformer.
66
In order to implement the standard solution, it is necessary two considerer two critical situation: 1) the phase’s dissymmetry of HV/MV transformer has to be lower than 0.5%, and 2) the HV neutral point of the HV/MV transformer should not be connected to earth. In case that this conditions are not fulfilled, it is adopted the solution of the Zig-Zag earthing transformer [62].
•
Considerations regarding the tunable (variable) and fixed coil. The operational results of the fixed and variable coil are the same when the compensation is total, this means that the reactive current produce by the coil is equal to the capacitive current of the network. In case of a topology change in the network, the compensation also change, therefore, in case of fixed coil it is necessary to modify their value manually, and this implies operation cost. The variable coil presents more flexibility under changes in the network since the coil is able to modify its value (inductance) according with the measure of the capacitance in the system. In table 6 are presented the result of the evaluation performances of automatic tunable coil with respect to fixed coil.
Higher interruption reduction, obtained with tunable coils with respect to fixed coils (2003 monitoring, 128 coils)
TOTAL TRANSIENT INTERRUPTION duration I¬-®¯°-±²³ ¤©´ !. The equation 4.3 presents the variable U to be solved according with the zero sequence current ( Io =
•ž
) and considering the compensated resistance of 200 ohms.
Figure 4.10 (Ground fault at bus bar 848 to obtain Rf for If 12A) •Ÿ. √¡
¢ ¤©µj
×
!• j
£3µ!•
=
"3.…
(eq. 4.3)
U = 1030Ω (eq. 4.3) The value obtained for
U is the limit to detect ground faults (at the farthest bus bar), this is a considerable
gain in the sensitivity of the protection in the presence of fault resistance, the ground directional protection will be able to recognize a ground fault with a fault resistance less than 1030 ohms. The location of the ground directional protection is depicted in the figure 4.11, there are three relays (67N and 50N).
Figure 4.11 (Ground directional protection scheme – 50N 67N)
104
Table 13a and 13b present the settings for the three sector relays indicated in the figure 4.11, it can be noted that the settings for the three ground directional relays have the same settings with the exception of the time delay, which have been chosen in order to guarantee a proper selectivity in the clearance of the fault depending on its locations.
50N Protective function Relay Tripping direction Residual Current 3xIo (A) normal condition Pick up current primary side (A)
R Sector 1
R Sector 2
R Sector 3
Forward
Forward
Forward
11
6
3,4
12
12
12
650
450
250
Time setting (msec)
Table 13a (Setting for relays 50N, Sectors 1, 2, and 3)
67N Protective function R Sector 1
R Sector 2
R Sector 3
Forward
Forward
Forward
Operation sector angle (deg) Operating current primary side (A)
40
40
40
12
12
12
Polarizing voltage primary side (V)
7000
7000
7000
Minimum residual voltage (V) Ground fault bus 848, Rf=1000Ω
8700
8700
8700
5
5
5
Relay Tripping direction
Maximum torque angle MTA (deg)
Table 13b (Setting for relays 67N, Sectors 1, 2, and 3)
The pickup current (protection 50N and 67N) is greater than the unbalance current for normal operating condition in order to avoid undesired trip when the system is in operation. Regarding the polarizing voltage threshold (7000 V), this lower than the residual voltage appeared for a ground fault with a fault resistance of 1000 ohm in the bus 848 (3xVo=8700V).
I setting 50N > 3xIo (normal operating condition) V setting 67N < 3xVo (ground fault at bus 848, Rf =1000Ω)
The logic used for the ground directional relay applied for the software Digsilent Power Factory is presented in the figure 4.12
105
Figure 4.12 (Ground directional protection scheme – Logic blocks)
In the figure 4.13 is presented the response of the three sector relays for a ground fault located at the bus 848 with a fault resistance of 1000 ohms, it can be seen the clearing time of the three relays according with the settings established in the table 13a, 13b and the logic protection scheme of the ground directional relay presented in the figure 4.12.
Figure 4.13 (Ground directional protection scheme – trip times for ground fault at bus 848)
The vectors of the grounded fault and the zero sequence voltage are presented in the figure 4.14 together with the tripping area established by the setting indicated in the table 13a and 13b. It is observed that the polarizing voltage vector and the ground fault current vector are within the operation zone of the ground directional protection, the figure 4.13 present the time selectivity of the three sector relays for the fault in the bus 848.
106
Figure 4.14 (Tripping zone of the ground directional relay for a ground fault at bus 848)
For comparative purpose was simulated the same fault (ground fault) at the bus 848 with a resistance fault of 1000 ohms and without the compensation resistance of 200 ohms in order to observe the response of the ground overcurrent protection (50/51N). In figure 4.15 are presented the time overcurrent curves of the three sector relays.
Figure 4.15 (Time overcurrent curves – ground fault at bus 848 with a fault resistance 1000Ω without Rn)
The ground overcurrent protections of the solid grounded distribution system are not able to send trip commands to the switching devices in the event of a ground fault with a fault resistance of 1000 ohms, this is serious disadvantages of the solid grounded system protections, the lack of sensitivity in the presence of fault resistance. Even in this case where there is a reduced fault current magnitude, the absence of tripping in the protection constitute a considerable source of risk for the system and the public in general.
107
In sum, the ground directional protection provides a better protection response even in the presence of fault resistance, which is a realistic assumption to design a protection system. The disadvantages of the ground directional approach is based in the limitation of the unbalanced current in normal operation condition, since the current setting of the protection has to be greater that the unbalance current in order to avoid unnecessary trips and the losses associated with the operation of the compensated resistance in normal operating condition.
The above mentioned reasons might justify the aim to change the load configuration in order to achieve a more balanced system where can be reduced this unbalanced load current in normal operation condition (3xIo). Nevertheless, in a real distribution system the change in the load configuration means a considerable amount of investment and effort, which can be feasible with the implementation of a penalty reward tariff scheme that allow to develop the necessary investments to improve the distribution system, it has been seen that the implementation of the compensation grounded scheme by means of a resistor in the test feeder network decrease the magnitude of the ground fault current and improve the performance of the protection by means of a gain in the sensitivity to detect ground fault in the presence of fault resistance.
4.5
Analysis of the temporary overvoltages of the IEEE 34-bus feeder test network
Once introduced the compensated resistance (200 ohms) in the distribution system it is necessary to check the existence of overvoltages in the network and the possible effects in the components of the network. Since the distribution network was previously a solid grounded system, the voltage ratings of the surge arrester was chosen according to the previous grounded scheme.
According with manufactures such as Siemens, the surge arrester recommended for a solid grounded system (four wire multigrounded neutral wye) with a nominal voltage of 24.9kV has the following characteristics: Duty cycle 18kV and Maximum continuous operating voltage 15.3kV [75]. It has been considered the ANSI approach since the test feeder network was developed by IEEE.
It has been simulated a ground fault event in the bus 802 (fault in the phase A) with the compensated resistance, as expected the healthy phases B and C experiment an overvoltages of 26.1 kV and 27.7 kV respectively, the fault resistance was neglected since in this scenario it is obtained greater values for the overvoltages in the healthy phases, and the objective is defining the new features of the surge arrester under the worst scenario possible. Figure 4.16 presents the vector diagram for the healthy phases (overvoltages) and the zero sequence voltages and current.
108
Figure 4.16 (Vector diagram, overvoltages phases B and C, ground fault in bus 802)
Once known the overvoltages for the worst condition (no presence of Rf), the next step consist on the calculation of new characteristic of the surge arrester for the overvoltages presented in the figure 4.16. According with the ground directional protection, the fault are cleared in less than one seconds, in principle, the overvoltages are present in the system for a maximum of 650 milliseconds according with the time settings of the relay sector 1, which is the main protection for its sector and the backup protection for the other two relays. Therefore, the transient overvoltages TOV will be 27.7 kV (phase C) and assumed to be withstand by one second. By means of the manufacturer curve characteristic (Temporary overvoltages vs time) will be obtained the MCOV (maximum continuous operated voltage) of the arrester for the overvoltages caused by the compensated grounded resistance. In figure 4.17 is depicted the curve characteristic of the arrester, it is allocated the value of the temporary overvoltage created by the ground fault event, TOV (27.7 kV) and obtained the value of the MCOV.
Figure 4.17 (U vs t curve characteristic of the arrester [75])
109
From the figure 4.17 it can be seen that the transient overvoltage TOV (27.7 kV) is equal to 1.6 times the MCOV (TOV = 1.6 x MCOV), hence, the maximum continuous over voltages MCOV corresponding to the TOV (caused by a ground fault event with a compensation resistance of 200 ohms) is equal to 17.25 kV. According with the manufacturer datasheet [75], the next superior surge arrester for a MCOV equal to 17.25 kV is the 19.5 kV MCOV option (with a duty cycle of 24kV). In table 14 are indicated the parameters for the surge arrester for solid grounded and compensated grounded method.
Grounded System Compensated System Compensated System
Maximum Continuous Operating Voltage MCOV (kV)
Duty cycle (kV)
Duty Class
BIL (kV)
15,3
18
Normal
141
19,5
24
Normal
162
19,5
24
Heavy
180
Table 14 (Surge arresters characteristic [75])
In normal conditions operation the surge arrester for the compensated system (normal duty class) will not be stressed by any overvoltages, since the maximum voltages in the network appears in the phase C (17.24 kV) is less than the MCOV value of the surge arrester (19.5 kV), in figure 4.18 is presented the vector diagram of the line to neutral voltage in the bus 800. In chapter five will be proposed a solution to solve the voltage unbalance problem in the network, and will be review the overvoltages presented in the system.
Figure 4.18 (Vector diagram of the line to neutral voltage at bus 800 normal operation condition)
The corresponding BIL for the surge arrester (heavy duty class) is 180 kV, nevertheless, the value of the BIL of the surge arrester might cause a loss of coordination of insulation with the rest of the network. One alternative could be chose a normal duty class surge arrester with a BIL equal to 162 kV. Further issues related with the insulation coordination in the compensated grounded system will be treated in the chapter five.
110
5. Reinforcement of IEEE 34-bus feeder test network with a compensated grounded system and conclusions According with the outcomes of the previous chapter, the introduction of the compensated resistance of 200 ohms produces high values in the residual voltage 3xVo along the distribution network (6.75 kV in bus 800, 7.42 in bus 816, and 7.85 kV in bus 832). The high value of the residual voltage creates a critical unbalance in the phase to ground voltages in normal operating condition, additionally the features of the surge arrester corresponding to the compensated system (Duty cycle: 24 kV, MCOV: 19.5 kV) have to coordinate with the insulation level of the system. In order to analyze to above mentioned problems. The first part of this chapter will describe the changes in the network aimed to reduce the residual voltage, and will obtain a new value of the compensated resistance which exploit the benefit in the reduction of 3xVo voltage, the second part deals with the verification of insulation level of the secondary side of the main power transformer with the features of the surge arrester for the compensated grounded system.
5.1. Reinforcement in the distribution network to improve the quality of service
The IEEE test feeder has been conceived to allow the connection of the monophasic loads, in some parts of the test network exist overhead lines with just one conductor to supply the loads, nevertheless, and accordingly with the outcomes of the chapter fourth, the phase to ground voltage levels appeared along the test feeder made unfeasible the connection for this type of loads. For illustrative purpose in figure 5.1 (vector diagram bus 848) is noted that the voltage value of the phase C (17 kV) presents an overvoltages of 1.18 p.u. (nominal phase to ground value: 14.38 kV), meanwhile, in phase A (11.75 kV) there is a under voltage 0.82 p.u.
Figure 5.1 (Vector diagram of the line to neutral voltage at bus 848 normal operation condition)
111
From a quality of service point of view, the system has been worsened with the introduction of the compensated resistance, the test feeder are not able to supply the monophasic loads in a sustainable way. In order to make feasible the introduction of the compensated scheme, it is necessary to perform some modification in the network aimed to overcome the problems associated with the over and undervoltages in the system. The modifications in the networks deal with the method for connecting the loads. Hence, the loads previously fed in a monophasic way will be connected using a line to line connection scheme according with the diagram presented in figure 5.2.
Figure 5.2 (New connection approach: line to line loads)
One of the main characteristic of the compensated grounded system in the event of a ground fault is related with the phase to phase voltages. When occurs a ground fault, the magnitude of the phase to phase voltages might remain unalterable, and the phase to ground voltages of the healthy phase withstand an overvoltages whose factor is √3. As seen in the section 2.1 this constitute a justification to size a high insulation levels for ungrounded and compensate distribution system. In figure 5.3 is observed the vector diagram of voltages in case of a ground fault event, in the case of no presence of fault resistance the phase to phase voltage keep the same, consequently, in the event of ground fault could be possible to continue to supply the loads if the fault current magnitude is below an acceptable limit that guarantee the security of the network and the public in general.
Figure 5.3 (Phase to Phase voltage for a ground fault event)
112
Once recognized the benefits of the line to line connection to supply the previously monophasic loads, the next step consist on listing the modifications to be performed in the distribution test feeder network. In sum, in case of monophasic load, it will be added a second phase in order to implement the line to line connection, and for the loads connected in wye connection, it will be implemented a delta connection. It is not considered a reschedule of the system loads, just in the connection type. In table 15 is listed the variations developed in the network.
Previous Connection
Present Connection
Line to Line Phases
Overhead line added (km)
Conductor type
Item
Load ID
Load variation description
1
L860
Change only in the connection type
3 Ph Wye
3 Ph Delta
w/o changes
0
-
2
L840
Change only in the connection type
3 Ph Wye
3 Ph Delta
w/o changes
0
-
3
L844
Change only in the connection type
3 Ph Wye
3 Ph Delta
w/o changes
0
-
4
L802-806
Change only in the connection type
2 Ph Wye
2 Ph Delta
w/o changes
0
-
5
L808-810
Line added
1 Ph Wye
B-C
1,8
4 ACSR
6
L818-820
Line added
1 Ph Wye
A-C
15,2
4 ACSR
7
L820-822
Line added
1 Ph Wye
A-C
4
4 ACSR
8
L816-824
Change only in the connection type
1 Ph Wye
A-B
0
-
A-B
0,8
4 ACSR
A-B
0
-
A-B
0
-
A-B
7
4 ACSR
Phase-Phase Phase-Phase Phase-Phase Phase-Phase
9
L824-826
Line added
1 Ph Wye
10
L824-828
Change only in the connection type
1 Ph Wye
11
L828-830
Change only in the connection type
1 Ph Wye
12
L854-856
Line added
1 Ph Wye
13
L858-864
Line added
1 Ph Wye
Phase-Phase
A-B
0,5
4 ACSR
14
L862-838
Line added
1 Ph Wye
Phase-Phase
A-B
1,5
4 ACSR
15
L842-844
Change only in the connection type
1 Ph Wye
A-B
0
-
w/o changes
0
-
A-B
0
-
-
-
-
Phase-Phase Phase-Phase Phase-Phase Phase-Phase
Phase-Phase
16
L844-846
Change only in the connection type
2 Ph Wye
17
L846-848
Change only in the connection type
1 Ph Wye
18
500 kVA Tr
Change in the winding connection
Wye Wye
2 Ph Delta
Phase-Phase Delta Wye
Table 15 (Variations in the loads to improve the quality of service)
113
According with the table 15, it is necessary to install 30.8 km of overhead line (4 ACSR) in the distribution network in order to make possible the line to line connection for some monophasic loads (items 5, 6, 7, 9, 12, 13, and 14). It has been assumed that the monophasic distribution transformers has two HV bushing with the same insulation level. In case of existing distribution transformer with just one HV bushing, the transformers have to be replaced by the two HV bushings transformer. For the rest of the loads, it was just necessary to modify the connection applied to them.
The transformer 500 kVA requires a modification in the primary side connections since the voltage unbalance that will be presented in normal and fault operation condition might stress and deteriorate the insulation of the primary windings. Hence, in case of a ground fault event, the primary side of the transformer (delta wye connection) will continue to withstand an almost unchanged line to line voltages (see figure 5.3), this implies an improvement on the quality of service.
Once implemented the variations indicated in the table 15, were simulated power flow and short circuit calculations to check the expected improvements in the network. In figure 5.4 and 5.5 are presented the vector diagram for the voltages of bus 800 and 848 respectively, both vector diagrams present a low value for the residual voltage 3xVo, in bus 800 the residual voltages has a value of 0.29 kV (2% with respect to the nominal line to ground voltage), and for bus 848 the residual voltage is 0.27 kV (1.9% with respect to the nominal line to ground voltage). The reduction in the residual voltage along the network represent a considerable improvement in the network performance.
Figure 5.4 (Vector diagram for Voltages bus 800, load connections modified, Rn=200Ω)
114
Figure 5.5 (Vector diagram for Voltages bus 848, load connections modified, Rn=200Ω)
An additional improved in the network is the reduction of the residual current since the wye load connections have been replaced by the delta and line to line connection. In table 16 are presented the value of 3xVo and 3xIo (power flow and short circuit) in the bus 800.
Compensated Resistance Rn (Ω) 200
3xVo (kV)
3xIo (A)
P-resistor (kW)
Short circuit Simulations 3xIo=If (A)
0,29
0,5
0,05
78
Power Flow Simulations
Table 16 (Variables for power flow and short circuit for load connections modified, bus 800, Rn=200Ω)
Consequently, with the above mentioned outcomes, it is feasible to explore an increase in the value of the compensated resistance in order to obtain a reduced value of the ground fault current magnitude. For the next analysis is used a compensated resistance of 400 ohms and will be checked the values of the residual voltages and currents.
In figure 5.6 is presented the vector diagram of voltages for the bus 800 with the new compensated resistance (400 ohms), meanwhile, in the table 17 are presented the results of load flow and short circuit of the same bus. The residual voltage obtained 0.59 kV correspond to the 4% with respect to the nominal line to ground voltage, this is a tolerable unbalance value to operate in normal condition of the system.
115
Figure 5.6 (Vector diagram for Voltages, bus 800, load connections modified, Rn=400Ω)
Compensated Resistance Rn (Ω) 400
3xVo (kV)
3xIo (A)
P-resistor (kW)
Short circuit Simulations 3xIo=If (A)
0,59
0,5
0,09
39
Power Flow Simulations
Table 17 (Variables for power flow and short circuit for load connections modified, bus 800, Rn=400Ω)
As expected, the reduction in the ground fault current magnitude make feasible a revision of the protective settings for the ground directional relay in order to gain more sensitivity in detecting the ground faults, which allow to the 67N protection scheme to detect ground fault events with greater values of fault resistance in comparison with the previous case (network without modification).
In table 17 is indicated a residual current value of 0.5 A, for normal operation condition, which constitute a considerable lower value with respect to the previous system (11 A). In order to calculate the maximum fault resistance that the improved ground directional protection is able to recognize as a fault event (i.e. maximum fault resistance that does not affect the sensitivity of the protection), the minimum threshold for the unbalance current that guarantee a trip in the presence of fault resistance, will be 3 A. The procedure is the same used in section 4.2. Figure 5.7 depicts the sequence circuit for a ground fault in the bus 848 considering the Rn value of 400 ohms, in the figure is introduced the fault resistance that produce the ground fault current magnitude of 3A.
116
Figure 5.7 (Ground fault at bus bar 848 to obtain Rf for If 3 A)
•Ÿ. √¡
¢ "3¤ j
×
!• j …£…!•
=
(eq. 5.1)
U = 4368Ω (eq. 5.1)
The value obtained for
U is a considerable improvement in the sensitivity of the protection scheme in the
presence of fault resistance, the ground directional protection will be capable to detect a ground fault with a
fault resistance less than 4368 ohms. In table 18a and 18b are summarized the settings for the protection scheme of the modified network, the pickup current of the 50N and 67N is 2 amps, the time delay of the three sectors relays was not modified since the duration of the voltage transient has an impact in the selection of the features for the surge arrester in the new compensated system. Therefore, the transient overvoltages will considered a maximum duration of 1 second. The residual voltage operating value has been modified also, since the introduction of the resistance value of 4368 ohms produce a reduced value of the residual voltage along the network.
50N Protective function Relay Tripping direction Residual Current 3xIo (A) normal condition Pick up current primary side (A) Time setting (msec)
R Sector 1
R Sector 2
R Sector 3
Forward
Forward
Forward
0,5
0,5
0
2
2
2
650
450
250
Table 18a (Setting for relays 50N, Sectors 1, 2, and 3, modified network, Rn 400 ohms)
117
67N Protective function R Sector 1
R Sector 2
R Sector 3
Forward
Forward
Forward
Operation sector angle (deg) Operating current primary side (A)
40
40
40
2
2
2
Polarizing voltage primary side (V) Minimum residual voltage (V) Ground fault bus 848, Rf=4300Ω
3800
3800
3800
3940
4040
4200
Maximum torque angle MTA (deg)
5
5
5
Relay Tripping direction
Table 18b (Setting for relays 67N, Sectors 1, 2, and 3, modified network, Rn 400 ohms)
Figure 5.8 (Tripping zone of ground directional relay for a ground fault at bus 848, modified loads, Rn 400Ω)
For illustrative purpose in figure 5.8 is depicted the residual voltage and current for a ground fault in the bus 848 considering a fault resistance of 4300 ohms. Comparing with the figure 4.14 (Rn 200 Ω, Rf 1000 Ω, and connection of loads without modification) the relative position of the residual current (ground fault) with respect to the residual voltage has no suffered great changes, hence, the operating sector angle and the maximum torque angle (MTA) does not require any modification.
5.2. Insulation coordination issues in primary substation equipment and distribution network
In this section will be checked the overvoltages produced in the network once modified the load connections in the test feeder network (improved network with a compensated resistance of 400 ohms). Hence, is required to identify the overvoltages produced in the network in case of ground fault events.
118
For illustrating the overvoltages impact in the system has been considered a ground fault in the bus 800 with no presence of resistance fault. Figure 5.9 presents the vector diagram of the overvoltages in the bus 800 focusing in the phase to ground voltages, these voltage magnitudes are withstand by the surge arrester (phase to ground connection).
Figure 5.9 (Vector diagram, overvoltages phases B and C, ground fault bus 802, modified loads network)
From the figure 5.9 is noted that the overvoltages in the healthy phases B and C are not different from the overvoltages obtained from figure 4.16 (network without load modification, Rn 200 ohms), consequently, the consideration about the surge arrester expressed in the section 4.5 are still valid for the modified network (compensated network Rn 400 ohms).
Hence, it is necessary to check the coordination insulation between the main substation equipment (power transformer LV side) with the features of the surge arrester (MCOV 18.5 kV, Duty Cycle 24 kV, normal duty class) applied for the compensated grounded system, it has been considered that the previous arrester features coordinate with the insulation of the system (former solid grounded system). The classification of the surge arrester depend on the voltage levels that the equipment will withstand (protection levels) and the current levels discharged through it [76]. In this sense, regarding the choosing of the distribution normal duty class surge arrester, it is assumed that the pollution and isokeraunic level are very low, therefore, the distribution normal duty class type has been chosen as a first option for insulation coordination calculations with the main distribution equipment (power transformer 2.5 MVA).
The electrical strength of insulation of transmission and distribution network equipment is expressed by means of three parameters, BIL (basic lightning impulse level), BSL (basic switching impulse insulation level), and CW (chopped wave lightning impulse insulation level). The insulation coordination analysis confront the three insulation parameters of the equipment with the corresponding protection levels of the surge arrester, which are listed as follow [77]:
119
•
Lightning impulse discharge voltage, 1.2/50 μs impulse protective level, which is compared with the BIL of the equipment (to be protected). For the surge arrester of reference [75], this protective value correspond to 63.8 kV
•
Slow front (switching surge) impulse protection level, this parameter is confronted with the BSL value of the equipment (to be protected).
•
Front of wave (FOW) impulse protection level, this surge arrester parameter is compared with the CWW (chopped wave withstand) value of the equipment (to be protected). According with reference [75], the FOW protective value is 77.6 kV
Figure 5.10 depict the comparison between the insulation strength of the equipment and the surge arrester protection levels. Regarding the lightning protection level of the surge arrester, it is considered a discharge current of 5 kA, which correspond to a normal duty class arrester. Is observed in figure 5.10 two protection margin that compares the insulation withstand levels of the equipment (Insulation withstand curve of LV side transformer 2.5 MVA) with the surge arrester protective levels (discharge voltage curve of the surge arrester).
Figure 5.10 (Insulation coordination protection margins criteria)
The standard IEEE C62.22 [78] provides the equations to calculate the two protective margins applied to distribution system insulation coordination. The insulation strength values for the transformer will be extracted from the standard IEEE C57.12.00 [79], meanwhile, the protective levels of the surge arrester are obtained from [75]. The expressions of the protective margins are as follow [78]:
PM\" = »¼
M½½
Nh½j\ Y\
¿ − 1À x100% (eq 5.1 [78])
p¾ p€
PM\3 = ÂI\ \J − 1Ã x100%
(eq 5.2 [78])
120
The first protective margin PM\" takes into consideration the connection lead wire voltage drop of the surge arrester. Considering the values used in [78], the voltage drop of the arrester connection lead for the main power transformer and distribution transformers are presented in table 19 (the length of the lead connections has been assumed).
Substation Distribution Transformer Transformer Inductance per length unit (uH/m) Length (m) Current rate-of-rise (kA) Voltage Drop (kV) (Lpl*l*di/dt)
1,3 1
1,3 0,5
20
20
26
13
Table 19 (Voltage drop of arrester connection lead [78])
The strength insulations values for the substation power transformer and the distribution transformer are presented in table 20. According with [79], for insulation levels purposes, the transformers (substation and distribution) belong to the class I classification. The outcomes of the protective margin calculations are summarized in table 21.
Substation Transformer Chopped Wave Withstand value CWW (kV) Basic Impulse Insulation Level BIL (kV)
Distribution Transformer
165
138
150
125
Table 20 (Insulated withstand value of transformer [79])
Substation Distribution Transformer Transformer Protective Margin L1
59%
52%
Protective Margin L2
135%
96%
Table 21 (Protective margin, power and distribution transformer)
The reference [78] states as general criteria that the PM\" and PM\3 values should be as minimum 20%, the outcomes presented in table 21 fulfil the protective rule of reference [78]. Consequently, the upgrading in the capability values for the surge arresters used in the test feeder network are valid from an insulation coordination point of view since still provide a required margin of protection, the increasing in the capability protective values of the surge arrester were motivated by the temporary overvoltages increment caused by the introduction of the compensated resistance (Rn 400 ohms). In figure 5.11 are summarized the strength insulation value of the power and distribution transformer together with the protective level value of the surge arrester (Duty cycle: 24 kV, MCOV: 19.5 kV).
121
Figure 5.11 (Insulation coordination protection margins, outcomes)
The surge arrester upgrading will protect the test feeder network according with the protective margin indicated in [78]. Nevertheless, the replacement of a considerable quantity of surge arrester in a real distribution network might present serious economic constraint. Because of the economic constrain, in reference [64] is analyzed the introduction of a series spark gap in the surge arrester in order to avoid the replacement of the arrester, the series gap is added to the arrester in order to withstand the overvoltages presented in the network caused by the introduction of a resonant grounding scheme.
5.3. Conclusions The analysis presented in this work has been aimed mainly to find the benefits of introducing of a limiting impedance in a previously solid grounded distribution network (IEEE test feeder network). The network under survey corresponds to a typical US distribution network used in rural areas where there are a strong present of monophasic loads connected along the entire network, consequently the distribution network presents some challenges to implementing a modification in the grounded scheme.
The first chapter evaluated the main features of the protection system, and important concepts to be considered when in the design stage of protection scheme. It was observed that the last generations of protection relays are able to hold several protection functions. The current protection solutions offered by several manufactures provides multifunctional relays, which contain the overcurrent functions and the ground directional function for feeder protection applications. In this sense, the new requirements in the protection scheme do not present considerable limitations to implement the compensation grounded scheme since modern relays are multifunctional.
122
Nevertheless, it was observed the necessity of dedicated voltages transformer and current transformer to measure the residual voltages and currents in order to implement the ground direction protection scheme, these instrument transformers should be sized considered the presence of the fault resistances, which affect the sensitivity of the ground directional protection scheme as a whole protection system.
In chapter two was presented the methods used for grounding the electrical networks, the neutral of the power transformer plays a key role in the grounding scheme of the entire system. With the exception of the solid grounded system, the other grounding methods present an overvoltages in the healthy phases in the event of ground fault. The overvoltages produced will depend on the grounding method applied and the value of the fault resistance involved, therefore, a changing in the grounding scheme necessary will imply a survey of the temporary overvoltages that withstand the insulation of the equipment when occurs a ground fault in the network. The ground fault events had a particular attention since this type of fault has the greatest probability of occurrence in electrical networks.
One of the main targets of the thesis consist on the evaluation of the motives to change the grounding scheme in existing a working networks. The chapter three are described the main driving forces to change an existing grounding scheme. It can be mention two important reasons to modify the grounding scheme. The first one concerns with improvements in the security in the network, since with the introduction of a current limiting impedance it is obtained a reduced ground fault current magnitude, which constitute an enhancements in the security of the networks and general public, the security motivations might obey to persistent problems and accidents in the network related with transitory or permanent ground fault events. The second reason deals with the necessity of improving the quality of service in the system, this motivation covers several aspects in the network operation, including the enhancements in the system security, the quality of service regulation is aimed to improve the operational indices of the system such as SAIDI and SAIFI, therefore, a current limiting impedance can support this aim since the protection scheme associated to it provides better outcomes in the selectivity and sensitivity to detect ground fault events. It is important to note that a quality of service regulation can allow a reward penalty policy (for DSO companies) which can support the investment in the network necessary to perform the required modifications and upgrading in the system.
The European experience such as the Italian case demonstrates that the service quality regulation is the main driving force to perform the change in the previous grounding method. From an insulated grounded approach, the distribution network changed towards a compensated grounding scheme, which allow to implement automation procedures to clear ground faults and consequently to obtain considerable improvement in the quality indices of operation. Within the benefits obtained of course include the reduction in the ground fault magnitude which means better security conditions. For the Italian case, the penalty reward tariff scheme has constituted a key factor for the implementation of the refurbish, upgrading, and improvement in the distribution network, besides the economics incentives from the regulation authority to develop demo projects and research conform an instrument to enhance the network operation. It can be concluded that a complete service quality regulation has to be designed to create the legal and technical framework in order to execute the investments and changes that need a distribution network aimed to obtain better economical a technical performance outcomes.
123
The Brazilian case of the distribution company AES do SUL presents the efforts developed to solve an urgent problem, which is, the security problem associated to the ground fault events. In this sense, the solid grounded approach was changed by a resonant grounding scheme, which measures the zero sequence impedance of the feeders to detect a ground fault condition. It is worthy to mention that for the Italian case the protection associated to ground fault allow to support the ground fault current until 18 seconds (protection located in the substation) with small affectations in the system insulations since the network was previously an insulated network. Meanwhile the situation of the Brazilian case allows to hold a ground fault event until 15 seconds, and it is necessary the review of the temporary overvoltages presented in the network, the insulation of the system was designed for a solid grounded approach, therefore, the overvoltages presented in the network represent a target to be evaluated to verify whether the insulation of the network might withstand the overvoltages generated by the new grounding method applied.
In the chapter four, the simulations of power flow and short circuit for the IEEE test network allow to observe that the introduction of the compensated resistance produces an increment in the residual voltages in normal operating conditions, in the worst case, the overvoltages and undervoltages registered values that reach to 1.18 p.u. and 0.82 p.u. respectively. These voltages profiles in the bus bar are not tolerable operating values, even more for the monophasic loads. It is concluded that the introduction of a compensated resistance in a previously unbalanced solid grounded system creates dangerous voltages levels in the network as seen in the section 5.1. Even though the benefits obtained reducing the magnitude of the ground fault current and the gain in the sensitivity by the ground direction protection scheme, the unbalance in the system voltages might became unfeasible the introduction of the compensating grounding, the phase to ground voltages magnitudes became the greatest limitation in the aim of changing the grounded scheme in the test feeder network.
To make feasible the introduction of the compensating resistance exist the necessity for changing the load connection scheme. In this sense, the chapter five evaluate the outcomes obtained with the modification of the load connection, the phase to ground connection was replaced with a line to line connection. With the introduction of the compensated resistance, the normal operating and short circuit conditions presents small variations in the line to line voltage, this features constituted the main reason to change the load connection scheme. It is concluded that the introduction of the compensated resistance has to be accompanied with additional changes and investment in the network since in some cases was necessary the addition of a second overhead line conductor to develop the line to line connection in the former monophasic loads. The investments in the network, necessary to make feasible the introduction of the compensated resistance might be supported and financed by means of a penalty reward tariff scheme, the improvement in the selectivity and sensitivity made by the ground fault protection scheme might help to improve the operational indices of the network.
An additional issue produced by the introduction of the new grounding scheme concern to the necessity for evaluating the temporary overvoltages produced in the network, once performed the change in the load connection scheme was observed that the phase to ground voltages withstand by the surge arrester should be modified since the previous solid grounded approach withstood lower values in the temporary overvoltages in the healthy phases for a ground fault event. In the chapter five it is concluded the need to change the surge arrester features (MCOV and Duty cycle values), additionally it was determined that the new surge arrester
124
protection levels are coordinated with the insulation levels corresponding to the main power transformer and distribution transformer, since the network is based on the IEEE test feeder, the insulation strength value were obtained from the IEEE standards. Nevertheless, for any real distribution network, the replacement of the surge arrester might became in an economical restrain. The bibliographic research oriented to find experiences to solve this problem (Brazilian case of AES do Sul), the alternative proposed consist in the introduction of a series gap in the present surge arresters to avoid any replacement, the series gap allow to withstand the new temporary overvoltages produced by the resonant grounding scheme in the network, and to perform the required responds when exist the present of a lightning discharge.
125
Annexes
Annex 1 Electrical characteristics of the IEEE 34-bus bar test feeder
The IEEE test feeder provides information about the configuration of the overhead lines of the distribution network, in table A1.1 is presented the configuration and the spacing of the overhead lines. In figure A1.1 is presented the dimension corresponding to the ID 500 and 510.
Overhead Line Configurations Config.
Phasing BACN BACN AN BN
Phase ACSR 1/0 #2 6/1 #4 6/1 #4 6/1
Neutral ACSR 1/0 #2 6/1 #4 6/1 #4 6/1
300 301 302 303 304
BN
#2 6/1
#2 6/1
Spacing ID 500 500 510 510 510
Table A1.1 (Overhead line configuration [71])
Figure A1.1 (Overhead line spacing – distance in foots [72])
The table A1.2 presents the characteristics of the aluminum conductors (ACSR) used in the configuration ID500 and ID-510, and the table A1.3 indicates the characteristics of the medium voltage cable (copper 19/33 kV three core light duty screened), there are shown the main features in order to perform the required simulations.
126
Aluminum conductors of overhead lines Size (AWG)
Stranding
Material
Outder Diameter (mm)
GMR (mm)
DC Resistance 20°C (Ω/km)
Nominal current 75°C (A)
1/0
6x1
ACSR
10,11
1,80
0,534
220
2
6x1
ACSR
8,01
1,19
0,851
165
4
6x1
ACSR
6,36
0,79
1,350
125
Table A1.2 (Conductor data [73])
MV Cable data
25kV 3/C
35kV 3/C
Voltage Rate (kV)
25
35
Insulation (%)
100
133
Size (AWG)
4/0
4/0
Nominal current Air (A)
348
348
Nominal current Ground (A)
369
369
AC Resistance 20°C (Ω/km)
0,164
0,164
Reactance (Ω/km)
0,126
0,146
Zero Seq Resistance (Ω/km)
1,368
1,266
Zero Seq Impendance (Ω/km)
0,99
0,768
Suceptance (µS/km)
83,31
61,22
Max Operation Temperature (°C)
105
105
Short circuit 1s (kA)
14,3
14,3
Table A1.3 (Conductor data [74])
Table A1.4 indicates the configuration of the each segment of the feeders along the network and the length of the segments. Table A1.5 presents the information related to the power transformers HV/MV and MV/MV
127
Line Segment Data Node A
Node B
Length(km.)
Config.
800 802 806 808 808 812 816 816 818 820 824 824 828 830 832 834 834 836 836 842 844 846 850 854 854 858 858 860 862
802 806 808 810 812 814 818 824 820 822 826 828 830 854 858 860 842 840 862 844 846 848 816 856 852 864 834 836 838
0,79 0,53 9,82 1,77 11,43 9,06 0,52 3,11 14,68 4,19 0,92 0,26 6,23 0,16 1,49 0,62 0,09 0,26 0,09 0,41 1,11 0,16 0,09 7,11 11,23 0,49 1,78 0,82 1,48
300 300 300 303 300 300 302 301 302 302 303 301 301 301 301 301 301 301 301 301 301 301 301 303 301 302 301 301 304
888
890
3,22
300
Table A1.4 (Line segment data [71])
Power Transformer Data kVA
kV-high
Substation:
2500
69 - D
XFM -1
500
24.9 Gr.W
kV-low 24.9 Gr. W 4.16 Gr. W
R-%
X-%
Tap changer
1
8
+/- 5%
1,9
4,08
+/- 5%
Table A1.5 (Power Transformer data [71])
The spot loads and the distributed load are indicated in the table A1.6 and table A1.7 respectively, in the table is indicated the load model to be used in the simulations. Table A1.8 shows the information related to the capacitor banks. Regarding the voltage regulator, the information about it is presented in the table A1.9.
128
Spot Loads Ph-1 Node
Ph-2
Ph-3
Model kW kVAr kW kVAr kW kVAr
860
Y-PQ
20
16
20
16
20
16
840
Y-I
9
7
9
7
9
7
844
Y-Z
135
105
135
105
135
105
848
D-PQ
20
16
20
16
20
16
890
D-I
150
75
150
75
150
75
830
D-Z
10
5
10
5
25
10
344
224
344
224
359
229
Total
Table A1.6 (Spot loads data [71])
Distributed Loads Node A
Node B
Load Model
Ph-1 kW kVAr
Ph-2 kW kVAr
Ph-3 kW kVAr
802 808 818 820 816 824 824 828 854 832 858 858 834 860 836 862 842 844 846
806 810 820 822 824 826 828 830 856 858 864 834 860 836 840 838 844 846 848
Y-PQ Y-I Y-Z Y-PQ D-I Y-I Y-PQ Y-PQ Y-PQ D-Z Y-PQ D-PQ D-Z D-PQ D-I Y-PQ Y-PQ Y-PQ Y-PQ
0 0 34 135 0 0 0 7 0 7 2 4 16 30 18 0 9 0 0
0 0 17 70 0 0 0 3 0 3 1 2 8 15 9 0 5 0 0
30 16 0 0 5 40 0 0 4 2 0 15 20 10 22 28 0 25 23
15 8 0 0 2 20 0 0 2 1 0 8 10 6 11 14 0 12 11
25 0 0 0 0 0 4 0 0 6 0 13 110 42 0 0 0 20 0
14 0 0 0 0 0 2 0 0 3 0 7 55 22 0 0 0 11 0
262
133
240
120
220
114
Total
Table A1.7 (Distributed loads data [71])
Shunt Capacitors Ph-A Ph-B Node kVAr kVAr 844 100 100 848 150 150 Total 250 250
Ph-C kVAr 100 150 250
Table A1.8 (Capacitor bank data [71])
129
Regulator ID: Line Segment: Location: Phases: Connection: Monitoring Phase: Bandwidth: PT Ratio: Primary CT Rating: Compensator Settings: R - Setting: X - Setting: Volltage Level:
1 814 - 850 814 A - B -C 3-Ph,LG A-B-C 2.0 volts 120 100 Ph-A 2,7 1,6 122
Regulator Data Regulator ID: Line Segment: Location: Phases: Connection: Monitoring Phase: Bandwidth: PT Ratio: Primary CT Rating: Compensator Ph-B Ph-C Settings: 2,7 2,7 R - Setting: 1,6 1,6 X - Setting: 122 122 Volltage Level:
2 852 - 832 852 A - B -C 3-Ph,LG A-B-C 2.0 volts 120 100 Ph-A 2,5 1,5 124
Ph-B 2,5 1,5 124
Ph-C 2,5 1,5 124
Table A1.9 (Voltage regulator data [71])
130
Annex 2 Time overcurrent curves for short circuit and ground faults
The annex presents the protection curves of the three sector relays considering a solid grounded distribution system. In the figure A2.1 are depicted the protection curves for the three sector of the network, it was simulated a short circuit (3 phase fault) at the bus 848 in order to show the time coordination among the three overcurrent relays installed in the network, it was not considered the presence of fault resistance.
Figure A2.1 (Time overcurrent curves – short circuit at bus 848)
The overcurrent relay of sector 3 (50/51) clears the short circuit in 0.39 seconds, meanwhile, the relays of the sector 2 and sector 1 provide the backup protection with a time coordination shown in the figure A2.1. It is important to note that the results change in the presence of fault resistance, this is one of the main causes of loss of selectivity.
The figure A2.2 indicates the time overcurrent current for the ground overcurrent protection of the three relays for a ground fault located in the bus 848, also in this event was not considered the presence of a fault resistance.
131
Figure A2.2 (Time overcurrent curves – ground fault at bus 848)
132
Index of figures
Figure 1.1 Definition of protection zones Figure 1.2 Overlapping of protection zones Figure 1.3 Overlapping limitations Figure 1.4 Time grading selectivity Figure 1.5 4th generation digital relay structure [8] Figure 1.6 Relays elements of numerical relay GE C60 Figure 1.7 Frequency response of low-pass filter [8] Figure 1.8 Illustration of sampling process in time and frequency domains [8] Figure 1.9 A/D converter with analog memory and multiplexer [8] Figure 1.10 Techniques of protection criteria measurements [8] Figure 1.11 Protection and control hierarchical structure [8] Figure 1.12 System function architectural diagram [8] Figure 2.1 Grounded scheme types Figure 2.2 Capacitive currents under one phase to ground fault Figure 2.3 voltage phasor in normal operation condition and one phase to ground faulted condition Figure 2.4 one phase to ground phasor diagram and magnitudes measured by residual CTs and VT Figure 2.5 Sequence circuit of solid grounded distribution system Figure 2.6 Capacitive and resistive currents under one phase to ground fault Figure 2.7 current and voltage phasor in one phase to ground faulted condition Figure 2.8 basic scheme for low resistance grounded system Figure 2.9 basic scheme for compensated grounded system Figure 2.10 a Sequence Circuit of the network b Reduction of sequence circuit Figure 2.11 Reduced sequence circuit of the network Figure 2.12 a) Full compensation b) Under compensation Figure 2.13 Schematic representation of insulation coordination of equipment [29] Figure 2.14 U-t characteristic of the arrester [29] Figure 3.1 Permissible Contact voltage values [33] Figure 3.2 Reward-Penalty linear incentive scheme [38] Figure 3.3 Quality of service improvement - SAIDI index reduction [39] Figure 3.4 NIST - SG Conceptual Model [47] Figure 3.5 Hierarchical overview of SG communication infrastructure [41] Figure 3.6 Overall communication infrastructure of SG [41] Figure 3.7 IEC 61850 Reference Model [51] Figure 3.8 IEC 61850 Protocol Stack Figure 3.9 DMS architecture – key elements [43] Figure 3.10 Communication Architecture POI-P3 project [55]
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Figure 3.11 General Architecture POI-P3 project [55] Figure 3.12 System Architecture InGrid project [56] Figure 3.13 RTDS Logical Scheme [57] Figure 3.14 HV network scheme Figure 3.15 Primary and Secondary substation scheme Figure 3.16 HV substation arrangements Figure 3.17 Basic protection scheme in PS Figure 3.18 Overcurrent Protection coordination in PS Figure 3.19 Petersen Coil basic scheme [63] Figure 3.20 Petersen Coil connection with Zig-Zag earthing transformer Figure 3.21 Equivalent circuit with a series resistor – ground fault condition Figure 3.22 Saturation decrease with an airgap CT. Blue=Primary. Green=Secondary [62] Figure 3.23 Residual Voltage and Fault resistance Figure 3.24 Busbar open-delta VT [25] Figure 3.25 Zero sequence circuit fig 3.24 [25] Figure 3.26 Typical Enel MV zero sequence voltage curve [25] Figure 3.27 Injection circuit [25] Figure 3.28 67N protection function – connection scheme Figure 3.29 67N protection function – trip zones Figure 3.30 Sector 1 – 67.S1 Figure 3.31 Sector 2 – 67.S2 Figure 3.32 Sector 3 – 67.S3 Figure 3.33 Sectors of 67N protection scheme Figure 3.34 Basic scheme of remote controlled secondary substation Figure 3.35 Current and voltage sensor in the line module Figure 3.36 Reclosing cycle of the FRG technique [59] Figure 3.37 Selectivity times and Reclosing cycle of the FNC technique [59] Figure 3.38 Enel DN smart grid communication network [57] Figure 3.39 A2A Architecture of communication network [57] Figure 3.40 Basic architecture for the FLISR approach: Power and Communication Network [50] Figure 3.41a Loop Mode – System Configuration [68] Figure 3.41b Loop Mode – Protection Equipment [69] Figure 3.41c Loop Mode – Logic Selectivity [69] Figure 3.42 Coordination of three device in a 4-wire DN [6] Figure 3.43 AES Sul – Scheme of reverse earth fault [37] Figure 3.44 AES Sul – Scheme of GFN system in the DN [37] Figure 3.45 AES Sul – Scheme of network to simulate the spark gap in the surge arrester [64] Figure 4.1 IEEE 34-bus feeder test network [71]
134
Figure 4.2 2.5MVA transformer wye open-capacitive current from the network Figure 4.3 Ground fault at bus bar 800 to obtain Rn for If 50A Figure 4.4 Variables for power flow and short circuit for different values of Rn Figure 4.5 Overcurrent protection scheme Figure 4.6 Time overcurrent curves – ground fault at bus 848 with a fault resistance 500Ω Figure 4.7 Vector diagrams of zero sequence quantities 3xVo, 3xIo for a ground fault in bus 802 Figure 4.8 Vector diagrams of zero sequence quantities 3xVo, 3xIo for a ground fault in bus 848 Figure 4.9 Tripping zone of the ground directional relay Figure 4.10 Ground fault at bus bar 848 to obtain Rf for If 12A Figure 4.11 Ground directional protection scheme – 50N 67N Figure 4.12 Ground directional protection scheme – Logic blocks Figure 4.13 Ground directional protection scheme – trip times for ground fault at bus 848 Figure 4.14 Tripping zone of the ground directional relay for a ground fault at bus 848 Figure 4.15 Time overcurrent curves – ground fault at bus 848 with a fault resistance 1000Ω without Rn Figure 4.16 Vector diagram, overvoltages phases B and C, fault in bus 802 Figure 4.17 U vs t curve characteristic of the arrester [75] Figure 4.18 Vector diagram of the line to neutral voltage at bus 800 normal operation condition Figure 5.1 Vector diagram of the line to neutral voltage at bus 848 normal operation condition Figure 5.2 New connection approach: line to line loads Figure 5.3 Phase to Phase voltage for a ground fault event Figure 5.4 Vector diagram for Voltages bus 800, load connections modified, Rn=200Ω Figure 5.5 Vector diagram for Voltages bus 848, load connections modified, Rn=200Ω Figure 5.6 Vector diagram for Voltages, bus 800, load connections modified, Rn=400Ω Figure 5.7 Ground fault at bus bar 848 to obtain Rf for If 3 A Figure 5.8 Tripping zone of ground directional relay for a ground fault at bus 848, modified loads, Rn 400Ω
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Index of tables
Table 1 Regulated service, frequently applied [38] Table 2 Main projects to improve the QoS - first regulatory period [40] Table 3 Domains and Actors in the SG conceptual model [47] Table 4 settings overcurrent protection Table 5 comparison of grounding method of PC [62] Table 6 Performance comparison automatic tunable coil vs fixed coil [62] Table 7 Settings 67N protection Table 8 Reduction in number of interruption by means of PC [59] Table 9 Open wye vs Grounded wye, sequence reactance, and ground fault magnitude Table 10 Variables for power flow and short circuit for Rn 320 ohm Table 11 Variables for power flow and short circuit for different values of Rn Table 12 Settings for relays 50/51 and 50/51N, Sectors 1, 2, and 3 Table 13a Settings for relays 50N, Sectors 1, 2, and 3 Table 13b Settings for relays 67N, Sectors 1, 2, and 3 Table 14 Surge arresters characteristic Table 15 Variations in the loads to improve the quality of service Table 16 Variables for power flow and short circuit for load connections modified, bus 800, Rn=200Ω Table 17 Variables for power flow and short circuit for load connections modified, bus 800, Rn=400Ω Table 18a Settings for relays 50N, Sectors 1, 2, and 3, modified network, Rn 400 ohms Table 18b Settings for relays 67N, Sectors 1, 2, and 3, modified network, Rn 400 ohms
136
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