POLITECNICO DI MILANO Alex... · POLITECNICO DI MILANO Scuola di Ingenieria Industriale e...

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

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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 Current trends in the protection systems ............................................................................ 21

2. 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

3. 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

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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

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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 Numerical protection relays

1.4.1 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])

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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 high-

frequency 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)

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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)

19

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:

∗ ! = "#∑ %& '!(')*− − , !-.// 0/1/ = "# ∑ * − , !-/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])

20

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:

. = 234" (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])

21

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

22

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].

23

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.

24

• 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.

25

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)

26

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: = @;: = @: = @ (Phase to ground total capacitance of each phase)

@ = @9:A + @9: (Total capacitance as the sum of the healthy and faulty component of each phase)

B; = CDEFGHDE = I−

3− √3 J @;: B;A = CDEFGHDK = I−

3 − √3 J @;:A

B = CGEFGHGE = I−

3+ √3 J @: BA = CGEFGHGK = I−

3+ √3 J @:A

B L = B; + B;A = I− 3− √3 J @;:

BML = B + BA = I− 3 + √3 J @:

BN9OPQ = B L + BML =−3 @). ?. = −3 @8)ℎ (eq. 2.1 [6])

27

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/" ≤ 3and 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].

28

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

29

• 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: ≤ IVWXYG JΩ (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)

30

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 toB 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:

31

U: ≤ ICWXYb 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.

32

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]:

^ = YWYd (eq. 2.4)

Where:

B\ Inductive current coming from the reactance :

BM Capacitive current of the system

33

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].

34

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 : and

resistance U: in parallel). The expression obtained for gS is the following:

gh = iX"jklMmin (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:

Bo = Cp"jklMmin!qinjE"jklMmin!r (eq. 2.6)

B = Cp"jklMmin!qinjE"jklMmin!r (eq. 2.7 one phase to ground current)

The residual voltage 8 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 = 38o =89 +8; + 8 8 = 3 × gh × −Bo!

8 = iX×CpinjE"jklMmin! (eq. 2.8)

35

The current measured by the residual CT in the healthy and the faulty feeders are the following:

BAo = 8SÀ

BAo =8S × @A BAo × 3 =8S × @A × 3 = BA BA = 8 × @A (eq. 2.9 residual current in the healthy feeder)

Bo = −t 8SÀ +8S3g:u

3 × Bo = −3 × t 8SÀ +8S3g:u

B = −3 × 8S t 1À +

13g:u

B = −8 t @A + 13g:u

B = −8 I @o − @! + "inJ (eq. 2.10 residual current in the faulty feeder)

According with eq. 2.8 the residual voltage 8 is dependent of the fault resistance, therefore, in case of high

resistance fault the magnitude of the 8 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 of8.

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)

36

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.

37

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

voltagevw1). ?. = √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 × ~√ (eq. 2.11 Solid earthed neutral networks)

vM,z: ≥ vw (eq. 2.12 Isolated or compensated neutral networks)

38

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 × ~√ (eq. 2.13 Solid earthed neutral networks)

v3 ≥ mm (eq. 2.14 Solid earthed neutral networks-second approach)

v" ≥ 1.25 × vw (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 voltagev, this means that the rated voltages v3 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" andv2, rounded up to a value

divisible by three. In case that the rated voltage v3 is greater thanv", 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.

39

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.

40

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 (B3 × ). 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].

41

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:

BB = ∑#h#\]2 VhNMw#h2VwY]#V#V#h#\]2 VhNMw#h2VwwVCV (eq. 3.1 SAIFI)

BB = ∑#

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:

BB = ∑Mw#h2V2Y]#VwhNY]#V#Yh]#h#\]2 VhNMw#h2VwwVCV (eq. 3.2 SAIDI)

BB = ∑ ×# = @B#

42

Where:

Restoration time for each interruption event

@B 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:

@BB = ∑Mw#h2V2Y]#VwhNY]#V#Yh]∑#h#\]2 VhNMw#h2VwY]#V#V = wYY

wYNY (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:

BB = ∑#h#\]2 VhNMw#h2Vw2h2V]#Y]#V#Yh]w#h#\]2 VhNMw#h2VwwVCV (eq. 3.4 MAIFI)

BB = ∑ B × z#

Where:

B Number of momentary interruptions

z 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.

43

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.

44

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.

45

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 on-

load switch in MV/LV substations (3 or 4 for each MV feeder), low cost/high performance Remote Terminal

46

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].

47

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].

48

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].

49

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.

50

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.

51

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])

52

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].

53

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.

54

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].

55

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.

56

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].

57

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 on-

load 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])

58

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 complete-

safe 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])

59

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.

60

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.

61

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

62

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.

63

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)

Time delay (sec)

HV SIDE (DV920 Protection device)

Overcurrent 1st Threshold 4855 0,6

Overcurrent 2nd Threshold 10020 0

MV SIDE (DV925 Protection device)

Overcurrent 1st Threshold 1156 1,5

MV LINE (DV901 Protection device)

Overcurrent 1st Threshold 360 1

Overcurrent 2nd Threshold 800 0,25

Overcurrent 3rd Threshold 1400 0

I nominal (A) 1156 HV/MV 20 MVA

20KV MV Side

I overload (A) 1618

I short-circuit MV side (A) 7707

Overcurrent setting are referred to the MV side

Table 4 (settings overcurrent protection)

64

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]:

65

• 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.

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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.

67

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.

TOTAL TRANSIENT

INTERRUPTION duration <1"

TOTAL SHORT INTERRUPTION 1" ≤ duration < 3"

TOTAL LONG INTERRUPTION

duration ≥ 3"

Higher interruption reduction, obtained with tunable coils with respect to fixed coils (2003 monitoring, 128 coils)

-26% -22% -10%

Table 6 (Performance comparison automatic tunable coil vs fixed coil [62])

• Introduction of parallel and series resistance to the Petersen coil. The parallel resistance to the PC

provides a resistive current component in case of one phase to ground fault (see fig 2.9 and 2.12), this

feature allow to use a wattmetric protection relay to detect a ground fault in the feeder, however, the parallel

resistor has no effect on the transient component of the ground fault current.

The inductance of the PC generates the DC component of the ground fault current (transient component),

which may causes the saturation in the CT (toroidal CTs are used to detect the residual current in the

feeders and in the compensated impedance). In order to avoid the saturation of the CT (in case of ground

fault condition), it is introduced a series resistor to reduce the time constant of the DC component produced

by the inductance of the PC, figure 3.21 presents the equivalent circuit of the network with the series

resistance, the series impedance of the feeders are neglected.

68

Figure 3.21 (Equivalent circuit with a series resistor – ground fault condition)

The practice introduced by Enel uses a time constant lower than 150 ms, and an active current in the

range of 35 to 45 A is assured by the resistor (parallel and series) including the internal losses of the coil.

Besides the contribution of the series resistor to decrease the time constant, the Enel technical

specification of the toroidal CTs includes an air gap to reduce the saturation of the magnetic circuit of the

CT [62].

In figure 3.22 it can be observed an oscillogram of the primary and secondary current (measured by the

CT with airgap) under a ground fault.

Figure 3.22 (Saturation decrease with an airgap CT. Blue=Primary. Green=Secondary [62])

• Voltage transformer connected in MV busbar. This instrument transformer is used to measure the

residual voltage of the network and provide a clear signal of the occurrence of ground faults. The residual

voltage magnitude is also used for tuning purposes of the PC by means of the network analyzer.

69

In presence of high values of fault resistance (in case of ground faults), the magnitude of the voltage

residual may be reduced in such a way to give a wrong measure by the residual voltage transformer,

equation 2.8 provide the relationship between the voltage residual and the fault resistance.

In figure 3.23 it can be noted that for high values of fault resistance the voltage measured presents a very

low value (in p.u. value)

8 = iX×CpinjE"jklMmin! (eq. 2.8)

Figure 3.23 (Residual Voltage and Fault resistance)

Therefore, in order to measure very low values of residual voltages, it is necessary that the voltage

transformer has the right accuracy in ration and angle since the position of the voltage residual is highly

important within the directional protection scheme regardless of wattmetric or varimetric purposes.

• Monitoring and control equipment of the compensated grounded network. The use variable coil allow

the PC produce different values of reactive current to be compensated with the capacitive current of the

network in ground fault conditions. The compensation factor (eq. 2.4) is defined as the ration of the reactive

(PC) and capacitive current of the system. When the reactive current is equal to the capacitive current the

compensation is 100%, in case to be lower than the capacitive current the system is undercompensated.

In order to set the compensation factor, it is necessary to have an idea about the capacitance of the

distribution network.

One of the most important magnitude to know that is the residual voltage measured in the MV busbar,

figure 3.24 presents a basic scheme of the connection for the residual voltage (open delta VT), it has been

neglected the series impedance of the MV lines and C represents the network line to earth capacitances.

The zero sequence circuit of the figure 3.24 is shown in the figure 3.25

70

Figure 3.24 (Busbar open-delta VT [25])

Figure 3.25 (Zero sequence circuit fig 3.24 [25])

When there is a full compensation by the PC, B\ = BM and c=1, therefore, the value of the inductance that

fulfill this condition is expressed by the equation 3.5 [25]. The value of the inductance ∗ drive the circuit

of figure 3.24 towards a resonant condition.

∗ = "lM (eq. 3.5)

The network analyzer (NA – DV 1027 equipment) receives the measurements of the residual voltage

from the open delta VT and calculates the capacitance of the network. Once know these two values, it is

possible to perform a desired compensation in the distribution network. The NA performs measurements

and tuning each three minutes when no faults conditions are present, on the contrary, it stop the

measurements and tuning. The NA can calculated the capacitances of the network by means of two

methods:

a) Inspection method, by means of this technique the NA moves the coil (change the value of the

inductance L) and measures the residual voltage, at the maximum value registered of the Vres

correspond the 100% compensation. It is a simple method and not injection of current or voltage are

necessary. In figure 3.26 is observed the shape of the residual voltage for different values of

compensation, at 100% of compensation reach the highest value.

71

Figure 3.26 (Typical Enel MV zero sequence voltage curve [25])

b) Injection method, in this technique the NA injects a signal into the zero sequence circuit (see figure

3.27) through the PC. The NA measures the residual voltage created by the injection89O!, in this

way, knowing the value of compensated impedance (g:) and the injected current signal (B\CM), it can

be calculated the network capacitance impedance (g) by means of the equation 3.6.

Figure 3.27 (Injection circuit [25])

89O = inH×iGHinHjiGH B\CM (eq. 3.6)

Where:

g:P_.gPCorrespond to the compensated and capacitance impedance referred to the LV side of

the injection circuit.

72

Additionally to the NA, there is the Neutral Manager Device (DV 936 equipment), which is installed in

the primary substation. This device is completely dedicated to the management of the switches

(associated to the PC system), coupling CB monitoring, and the network analyzer status. The neutral

manager device is able to perform the followings actions in an automatic way:

o Opening and closing of switches according to predefined logics

o Pilots the NAs to master/slave mode in case of coupling the MV bus bar of the primary substation

(CB is closed by remote operation)

o Monitoring of switches, networks analyzers, and impedance equipment (PC plus resistors) in order

to detect faults or abnormal conditions.

o Send signals to the remote control room

• Use of earthing resistor instead of PC (the theoretical framework was dealt in section 2.3.1, high

resistance grounded method). In case of distribution networks with low capacitive currents, which mainly

corresponds to overhead feeders (earth fault capacitive currents lower than 60A with reference to 20 kV

operation voltage), Enel realizes the connection to earth of neutral points by means of a resistor of 770 Ω

(approximated value). Considering the low phase to ground current magnitude, this resistor ensures an

acceptable probability of self-extinction faults and the elimination of the arcing faults [23].

3.3.4. Directional earth protection scheme, the new approach of Enel

The ground faults in the system has the greatest probability of occurrence among the other type of faults,

therefore, the efforts to improve the protection schemes have been directed to provide better protection devices

to respond in a very selective and reliable way. Since the introduction of Petersen coil in parallel with a

resistance, the magnitude of the one phase to ground current are highly reduced to values that are not

dangerous for equipment and people. This new grounding method of the neutral in the distribution system

requires an update of the directional protection scheme to respond to the ground faults. Additionally, the

direction protection device should be able to respond to ground fault under an isolated grounded system, this

can occurs when the compensation system (Petersen coil and resistance) may not be available for

maintenance reason.

In figure 3.28 is presented the connection for a residual directional overcurrent relay (ANSI code 67N), the

residual current and residual voltage signals come from a toroidal CT and an open delta VT (at the MV busbar

of primary substation) respectively. This scheme applies for the directional protection installed at the departure

of the MV feeder. Along the distribution line, it is installed the 67N protection within the cubicles of the switch

disconnectors of the secondary substation.

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Figure 3.28 (67N protection function – connection scheme)

Enel has develop a directional protection scheme that is capable to select a phase to ground fault regardless

of the neutral method used and without any external information about the neutral status. The residual

directional protection 67N process:

• Residual voltage through the open delta VT (Vres)

• Residual current through the toroidal CT (Ires)

• Phase position between the residual voltage and residual current

The 67N protection function will send a trip command if three condition are verified at the same time (AND

logic):

• Residual voltage is greater than the setting value &

• Residual current is greater than the setting value &

• Phase position is inside the setting angle difference

Figure 3.29 present the operation zones of the 67N protective function, the trip operation is performed

depending on the relative positive of the residual current with respect the residual voltage Vres (polarized

magnitude). There are three intervention sectors used by the directional earth fault protection, which have

been developed for compensated, isolated and cross country fault conditions [61].

Figure 3.29 (67N protection function – trip zones)

74

The sector 1 (67.S1), correspond to situations involving a compensated network, Petersen coil and parallel

resistance are connected to the MV neutral bushing of the power transformer. In this condition, the residual

current of the healthy feeders is 90° leading the residual voltage (Vres). Besides, the phase of the faulty

feeder residual current is a variable that depend on the line length and the compensation factor and is

independent of the fault resistance, a minimum value of 13° for is necessary since the accuracy of the

instrumental transformer. In figure 3.30 is depicted the vector diagram corresponding to the sector S1.

Figure 3.30 (Sector 1 – 67.S1)

The sector 2 (67.S2), involves an insulated network conditions. The residual current in the healthy feeder is

90° leading the residual voltage (Vres). Meanwhile, the residual current in the faulty feeder is 90° lagging the

residual voltage, figure 3.31 shows the vector diagram of the sector S2.


75

The sector 3 (67.S3), corresponds to the protection of the system for cross country faults (double single phase

earth faults). The cross country fault begin as a one phase to ground fault and since the overvoltages caused

by the initial ground fault, a healthy feeder in other location of the network became to a ground fault, therefore,

in the systems exist a double single phase earth fault. A simple residual overcurrent relay is not sufficient to

protect the feeders under a cross country fault, it is necessary to know the direction of the fault current takin

into account a reference magnitude, in this sense, a residual directional protection is required. Concerning the

threshold of the residual current of the function 67.S3, this setting must be greater than the large line

contribution to earth fault, otherwise, in case of earth fault, a healthy line could trip. Figure 3.32 shows the

vector diagram of sector S3, it can be observed with one of the two faulted currents will be located within the

operation trip area.


The Enel solution for the direction protection in distribution networks is able to adopt three separated group of

threshold (for sectors S1, S2, and S3) completely independent and contemporaneously active. Using this

approach it is not necessary any external command to change the tripping sector. The thresholds (residual

voltage, residual current, and tripping area) of the three sectors are independent and different too. In figure

3.33 is observed a superposition of the three sector.

Figure 3.33 (Sectors of 67N protection scheme)

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In table 7 presents the settings for the three sectors of the residual directional overcurrent relay 67N.

Sector Residual Current (A)

Primary side CT 50/1 A

Residual Voltage (V)

Secondary side Open delta VT

Angular Sector

Trip Time

(s)

67.S1 2 5 - 6 60 - 257° 20*

67.S2 1 - 2 2 - 15 60 - 120° 0,4

67.S3 150 2 190 - 10° 0,1

* This value is coordinated within the FNC scheme and the downstream relays along the MV feeder

Table 7 (Settings 67N protection)

Besides the three direction protection mentioned above, Enel has considered other two special protection to

avoid an improper transformer protection tripping [61]. The additional protection features avoid the tripping of

the transformer earth fault backup protection (max Vo) when the MV feeder is subject to a re-striking (67.S4)

or progressive fault (67.S5).

3.3.5. Secondary Substation and Automation techniques

The new grounding approach in the primary substation has been carry out in parallel with projects to improve

the remote control, supervision, and automation of secondary substation. The automation capabilities

introduced in the secondary substations constitute one of the main factor to reach the targets established by

the regulator authority, besides, the introduction of the DG made necessary to provide the secondary

substations with communication capability. The main components of the remote controlled secondary

substations are presented in the figure 3.34.

Figure 3.34 (Basic scheme of remote controlled secondary substation)

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The line module contains a motorized switch disconnector which receives open and close commands from the

UP. The command signals from the UP are generated for protection motives (RGDAT or RGDMA) or issued

from the control center.

It can be noted the voltages and current signals from the line module towards the protection devices RGDA,

the signal are obtained by means of the sensors (rogowski coil for current and capacitive divider for voltages)

installed within the module, which allow to RGDAT to detect phase to earth faults, phase to phase faults, and

presence/absence of voltages, figure 3.35 presents a scheme of the sensors used in the line module.

Figure 3.35 (Current and voltage sensor in the line module)

The automation on MV system is based on a group of automatons allocated into the UP memory. The UP is

able to control the automatic opening and closing of disconnectors, according with specifics procedures,

therefore, when a fault is detected by an RGDM (or RGDAT), the disconnector is operated by the automation

of the UP, the goal is the isolation of the faulty section of the feeder and the resupply of the healthy section.

The automation procedures involve more than one UP, each UP uses just local signal. In order to develop a

reliable automation procedure, no communication is required among the several secondary substations or

between secondary substation and central system. The automatons can be programmed, activated,

deactivated and trimmed by commands form the control center. The main two schemes of network automation

are the FNC and FRG technique, by means of these two procedures, the secondary substation switching

devices and the MV circuit breaker (at the line departure of the primary substation) execute the actions to

extinguish the faults (short circuit or one phase to ground faults) that can occurs in the MV feeder [58, 59].

FRG Technique

This scheme is used on cables and overhead lines (time parameters are different), with both neutral

configuration method (isolated or compensated). The UP, by means of the fault detectors, reads information

from the field: voltage presence (line-side) and fault presence (short circuit). The rules are the following [58,

59]:

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Rule 1: the switching device is opened if a voltage absence is observed for a period of time (5 seconds for

underground lines, 35 seconds for overhead or mixed type lines), and a fault is detected.

Rule 2: the switching device is closed (in case of more automated switches are present, exist a priority order)

when is detected a voltage restoration due to the reclosing of the MV circuit breaker (secondary substation) or

the switch located upstream.

Rule 3: a switch is opened and locked in the open position when performing the closing operation according

to the rule 2, there is a lack of voltage and at the same time there is detected a fault, both within a time window

beginning from the close position of the switch. This lock in the open position of the switch produce a calls

towards the control center. Otherwise, the automatism is into the state “inibizione all aperture automatic”.

Figure 3.36 (Reclosing cycle of the FRG technique [59])

Figure 3.36 presents the reclosing cycle of the FRG technique, the reclosing operations is performed by the

MV circuit breaker located in the primary substation. The reclosing cycle is execute in parallel with the

automation procedures allocated in the UP of the secondary substations, in this ways it is possible to locate

and isolate a faulty section in the network.

FNC Technique

The FNC scheme is applied on cables and overhead lines, however, is only used on grids with a compensated

grounded scheme. The logic implemented is depended on the type of fault detected by the RGDAT (or RGMD),

for short circuits (overcurrent function) the logic perform as in the FRG procedure, and for one phase to ground

fault (earth detector) the automatons perform in such a way to disconnect the faulty section without any tripping

of the MV circuit breaker at the line departure.

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In the case of ground faults, the FNC technique has a specific procedure (i.e. reclosing cycle). The basics rules

execute by each switching device (commands come from their associated UP) are the next:

Rule 1: the switching device is opened and locked (after a programmed delay) if there is an intervention of the

earth fault detector and the intervention itself stay until the end of the established delay.

Rule 2: the programmed delay of the automated switch is calculated depending on the position of the

secondary substation in the MV feeder, this delay times are setting to establish a time selectivity clearing of

the faults.

It can be arise two cases. The first case, where the fault is not located in the first section of the feeder, the MV

circuit breaker at the line departure stay closed, in this way any interruption on the healthy sections located

upstream the fault are avoided. The second case, when the fault occurs in the first section, the MV circuit

breaker execute all the reclosing cycle and trips definitively. Whichever the case, it caused the call towards

the Control Centre. Figure 3.37 presents the schemes of the FNC technique after the selectivity times are

performed (according with the position of the fault in the network) and in case that the fault is persistence, the

MV circuit breaker execute the reclosing cycle depicted in the above mentioned graphic.

Figure 3.37 (Selectivity times and Reclosing cycle of the FNC technique [59])

3.3.6. Benefits of the Petersen Coil approach

From an economic point of view, the introduction of the new grounding method has been evaluated considering

three factors responsible of the economical return of the system [23]:

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a) Decrease in the number of interruptions and, consequently, a reduction of the cumulative duration for

LV users (sum of number of interruptions per duration of the interruption). This aspect represent the

major part of the economic benefits related to savings caused by the enhancements of quality indices.

b) Reduction of periodic test and intervention on earth plant. The reduction in the magnitude of the ground

fault current produce a decreasing in the touch voltage, allowing a higher permissible time to clear the

ground faults. This aspect is highly related with improvements in the security (section 3.1.1) of the

installations in the secondary substation and active/passive consumer installation.

c) A reduction of the technical personnel to localize the faults, since a reduced number of interruption is

obtained by means of the new grounding method. The automation enhancements in the secondary

substation also help in the reduction of teams to develop a corrective maintenance since the ground

faults.

In table 8 [59] are indicated the net reduction of the number of interruptions, the reduction was only due the

introduction of the Petersen coil. The data are referred to the period 2001-2003 (first regulatory period), the

most remarkable outcomes correspond to the 2003 year. In general, the analysis was developed considering

each bar compared with itself in the same period of the previous year, and other sources of improvement was

removed.

Table 8 (Reduction in number of interruption by means of PC [59])

The introduction of the compensated grounded method in the distribution network of Enel has created several

benefits, among the more important can be mentioned the followings:

Reduction in the magnitude of the one phase to ground current, this reduction improve the security issues

associated to the installations connect in the MV network, this allow a saving cost in the grounding plant

of the installations. Additionally, by means of this reduction is possible for a switch disconnector clears a

ground fault, the fault current magnitude correspond to tens of amperes, meanwhile, the nominal current

of the switch disconnector is 400 A.

Reduction in the transient interruption (duration less than one minute). Since the ground faults correspond

to the greatest percentages of faults occurred in the network, the new automation technique FNC allow to

the transitory fault be extinguish.

The reduction in the magnitude of the ground fault current implies lower stress in the equipment affected

by the fault. On the contrary to the solid grounded networks whose ground current magnitudes reach

thousands of amperes causing dangerous condition to the installation and people.

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Reduction of the risk of restarting arc, since the voltage increase after the extinction of the arc is slow.

The insulation of the system is monitored, in this way it can be performed activities of preventive

maintenance of the network.

The FNC technique allow to keep close the MV circuit breaker at the departure of the line since there is a

time delay settings in the protective device associated with this automatism. After the time delays are

expired in the protection devices, it is performed the reclosing cycle to clear the fault.

3.3.7. Enel Communication Network

The new goals and objective of the DSO require a robust communication network that respond to the

challenges presented by the introduction of DG and the policies regarding a service quality regulation. In this

regard, the fast respond of the DSO infrastructure towards any abnormal condition is highly required, since the

indices of quality of services released by the regulator are translated in a reward or penalty in the incomes of

the DSO. Therefore, in order to fulfill the goals of the regulator’s police, the improvements of communication

infrastructure is a fundamental factor.

The communication network provides the means for a reliable exchange of information among the several

IEDs and RTUs allocated in the primary and secondary substations, including the installation of active and

passive consumers. In general, the communication in the primary substation follow an “always on” approach,

meanwhile, the exchange of information in the secondary substation is “on demand”.

Figure 3.38 (Enel DN smart grid communication network [57])

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Figure 3.38 show the communication network concerned to the MV network of Enel, it can be seen the several

IEDs (RGDM, IC, DV7500, and DV7300) and RTUs (UP, TPT2020) connected by different networks, which

are mentioned as follow [57]:

WAN: is the Wide Area Network that connects all secondary substations connected to the MV feeders, WAN

supports IEC 61850 GOOSE and MMS messages and TCP-IP traffic, the physical topology could be ring or

hub-spoke.

PS LAN: correspond to the primary substation LAN, this ring topology network connects the DV901/A3 feeder

protections, the DV7500 transformer panel (protection and control) and the TPT2020 RTU.

SS LAN: refers to the secondary substation LAN, it connects the RGDM (advanced fault detector) and the UP

RTU by means of a 101 to 104 protocol converter

FCP LAN: is the LAN network of the full controllable plan, this network connects IREHW (control of DG) and

DV7300 devices (protection of DG).

STM: is the Enel SCADA, is capable of manage all IEDs above mentioned

DMS: Distribution Management System, is a platform that hold engineer applications that can support the

operation of the DN in on-line and off-line way.

3.3.8. State of the Art in Italian Distribution Systems

The quality of service regulation in Italy establish the policies and indices that should be fulfilled by the DSOs,

in this way the regulator has created a penalty/reward system which constitute a great driven force to improve

the performance for all the DSOs. Companies such as Enel Distribuzione and A2A have develop several

projects to improve the communication infrastructure in order to support new protection schemes and the

topology of the MV distribution network. It is worth to mention three projects aimed to develop the new schemes

in protection and topology improvements.

Broadband Power Line Communication by A2A

A2A has launched a research aimed to use the MV network as communication media by means of power line

carrier technology. Since the high cost associated to the fiber optic (FO) to establish a communication among

the primary substation and the secondary substations, the MV-PLC could be a convenient solution to establish

a reliable communication exchange among substations that use IEC 61850. The research developed by Della

Giustiana et al present the results of the first stage of a project whose final outcome is the implementation of

automation based in IEC 61850 for the distribution networks, the experiments have been developed in a real

network. The research evaluates the feasibility of the MV-PLC as a communication network for IEC 61850,

and in order to avoid the installation of additional instruments it is used the Internet Control Message Protocol

(ICMP), the ICMP services is adopted to assess the round trip time (RTT), which is defined as the time the

information need to reach a destination node and came back to the source, the RTT is a parameter that

provides a reference about the performance of the communication network. The experiments developed by

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A2A have employed devices derived by the OPERA standard and working in the 2 -7 MHz and 8 -18 MHz

bands. The results of the experiments of A2A have shown that the RTT evaluated is under the 40 ms in more

than the 99% of the cases (just considering the links involved in an IEC 61850 communication), it was

concluded that the MV-PLC satisfied the minimum requirements (acceptable delays) in order to go forward the

next stage of research. In figure 3.39 it is presented the architecture of the communication network under

consideration [66].

Figure 3.39 (A2A Architecture of communication network [57])

Adaptive Logic Selectivity using IEC 61850 by A2A

The logic selectivity protection approach is based on the configuration of the network, thus, if there are changes

in the topology of the network the logic selectivity approach have to be updated in order to work well and

perform a correct trip orders. The FP7 European Project IDE4L propose and adaptive fault location, isolation,

and service restoration cycle (FLISR), which is based on logic selectivity, in this approach the protection system

is configured in an optimized way regardless of the network configuration. In this sense, in [50] is proposed

the modelling of protection devices using IEC 61850 logical nodes, the updating of the protection settings, and

logic in real-time. The proposed approach for FLISR is based on the distribution of the involved control and

monitoring logics (applied to the MV network and theirs switching devices). The FLISR architecture require the

cooperation of the different protection IEDs installed along the feeder, additionally, the IEDs have to

communicate with the central unit of the primary substation. By means of the IEC 61850 GOOSE, each IED is

able to exchange information (e.g. exchanging fault detection events to define the IED closest to the fault) with

the others using a publisher/subscriber communication [50].

The detection and isolation components of the FLISR algorithm are based on the criteria that every IED

subscribes the IED located downstream the same feeder as its publisher. In the presence of a fault in any point

of the feeder, the IEDs that detect the fault send a GOOSE message to their subscribers, in this way the only

IED that sends a GOOSE without receiving at least one message from their publisher is the nearest to the

fault, this IED is the only one allowed to trip its breaker [67].

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Figure 3.40 (Basic architecture for the FLISR approach: Power and Communication Network [50])

The substation automation unit perform as a subscriber of each IED associated to the feeders, therefore, each

time a fault is detected and isolated, the substation automation unit knows where the fault is located, and by

means of optimized algorithms (state estimation, forecast, and optimal power flow) is able to determine the

best reconfiguration of the grid. The introduction of IEC 61850 standard as a shared model for the protection

IEDs parameterizations and description simplify the reconfiguration steps. In sum, after a network

reconfiguration the primary substation automation unit (know in advance the new network topology) updates

the configuration of the protection IEDs involved in the reconfiguration process, it can be noted that a common

modeling of protection function settings allows an adaptive reconfiguration of the protection system [50].

Closed Ring operation in MV Network by ENEL

The continuous pursuit of improvement in the operation of the MV networks has driven to reconsider the

classical radial operation mode of the grid. In this sense, Enel launched the P4 Project, funded by the Italian

Ministry of Economic Development, the P4 Project was developed within an Innovation Program carried out in

4 regions of the South of Italy (in the frame of the Programma Operativo Interregionale POI).

In theory, the implementation of a closed ring the MV network may produce improvements in the management

of DG in relation with issues such as voltage profile, power losses, and reliability, in this way there is an

increment in the hosting capacity of the grid, besides the introduction of DG creates the condition of

bidirectionality of the power flows in the MV feeders. The P4 Project evaluates two main functionalities of the

close ring network, in ordinary network condition (close ring operation), and the test of the grid in case of faults

(fault selection along the MV loop) [68].

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Figure 3.41a (Loop Mode – System Configuration [68])

In figure 3.41a is presented the system configuration of the loop mode network under test. The network chosen

to form the loop is constituted by two MV feeders departing from the same bus bar in order to limit the

complexity of the system itself. The ordinary operation of the closed ring represent a new condition to be test,

but in general is not so complex in comparison with the faulted conditions to be appeared in the close loop

mode [68].

The P4 Project implements a new approach for fault selection, in the close loop mode (ground faults or short

circuits) just the smaller section possible of the feeder is disconnected, this means that the unsupplied section

of the feeder should be limited to the one confined by two MV/LV substations, therefore new functionalities are

required. In first place the equipment located in the MV/LV substations have to perform as protection relay at

the same time should keep the features of easiness of use. Second, the switching devices must be capable to

open and make short circuit currents. Third, the communication network should work in an always-on mode in

order to operate in real time and ensured the timely intervention of the switching devices. Regarding the

communication issues, it is necessary that the IED installed along the loop include the necessaries

communication capabilities, the application protocol to be implemented is the IEC 61850, it is used optic fiber

in the feeder sections consisting on overhead lines, and Wi-Fi for the underground lines [68].

The protection of the loop network is performed by the IED located in the secondary substation and the primary

substation (departure of the MV feeder), it is used a logical selectivity approach to minimize the unsupplied

section. The two type of IEDs used by ENEL are the DV901 and the RGDM, in figure 3.41b is presented the

allocation of this IEDs [69].

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Figure 3.41b (Loop Mode – Protection Equipment [69])

In a loop operation mode, the protection selectivity scheme has to differentiate between two cases (in the

event of one phase to ground faults), when the fault occurs within the loop network and outside the loop (faults

in radial feeders). For the first case (fault within the loop), both DV901 detect the fault in forward direction,

within the loop some RGDMs detect the fault in forward direction (red arrows fig. 3.41c) and some RGDMs

in reverse direction (green arrows fig. 3.41c), all of the RGDMs that detect the fault in forward direction send

a lock signal to the upstream RGDMs, therefore, the only RGDMs (or DV901) that does not receive the locked

signal must trip, the RGDM that detect the fault in reverse direction does not trip. In the second case (fault

outside the loop), both DV901 detect the fault in reverse direction (green arrows fig. 3.41c), however, inside

the loop some RGDMs detect the fault in forward direction (red arrows fig. 3.41c), the RGDM that see the fault

in the forward direction send a lock signal back, at the same time the DV901 (see the fault in reverse direction)

send a lock signal to the firsts RGDM in opposite direction in order to lock them, the logic selectivity scheme

avoid undesired tripping inside the loop and allow to trip only the radial feeder. The exchange of information

among the IEDs that conform the loop is based on IEC 61850 [69].

Figure 3.41c (Loop Mode – Logic Selectivity [69])

A close loop topology permit a better management of the grid, since each part of the feeder has an equal

importance in terms of interruptions. For each type of fault it is possible to interrupt just a restricted part of the

feeder avoiding the total interruption of users, therefore, will be guarantee a same risk of interruption for all of

the users. In this way, the close loop topology contributes to improve the continuity of supply, decreasing the

number and duration of interruptions [70].

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3.4. First steps towards the change: Brazilian case, from solid to compensated grounding system

The solid grounded method applied in the distribution networks is used in countries such as Mexico, Australia,

United States, and many South American countries like Brazil. In a solid grounded approach, it is used a 4

wires system, in this scheme the neutral (the 4th wire) is grounded in multiple points along the feeder. In

distribution network, the 4-wire system allows to connect single phase loads along the feeder by means of

distribution transformer in order to supply with a low voltage level to the consumers. The 4-wire system with a

solid grounded approach, allow to the distributor system operator (DSO) some economic savings in the

expansion of the network since the system is able to connect single phase loads with the medium voltage

feeders. However, one of the greatest disadvantages is concerning the magnitude of the one phase to ground

current, this ground fault current can reach tens of thousands amperes, therefore, the security of people and

the integrity of equipment are seriously at stake.

In the presence of ground fault conditions, the protection schemes of the distribution network is compelled to

clear the fault in the shortest time possible, generally, in 4-wire distribution system (solid grounded) the

protection schemes are conformed by overcurrent relays, reclosers, and fuses located along the feeder. It is

implemented a time coordination approach among the protection devices in order to clear the fault that can be

presented in the network. Figure 3.42 presents a typical case of coordination between three devices, device

C is a line fuse, device B is a line recloser, and device A is a relay that command a circuit breaker in the primary

substation, it can be noted a coordinated time of 0.35 seconds between the minimum melt time of the fuse and

the recloser (response time of the controls of the recloser) for a fault in the location 1, and also between 0.35

seconds between the recloser and the relay [6]. However, this system has some disadvantages in the presence

of high values of fault resistance.

Figure 3.42 (Coordination of three device in a 4-wire DN [6])

The overvoltages occurred in the healthy phases do not constitute a serious issue in a solid grounded system,

the insulation of the equipment (phase to ground bushings) are sized to withstand the value of the maximum

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continuous voltage of the system (phase to ground value). On the contrary, in the resonant and insulated

system, the insulation of the equipment should be able to withstand the phase to phase value of the maximum

continuous voltage of the system.

Based on the above mentioned, the change of the grounding method from an insulated approach towards a

compensated method, do not imply critical issues regarding the insulation of the system, since the insulated

system is able to withstand the same overvoltages levels as expect in the compensated system (overvoltages

caused by ground faults). On the contrary, in the case that a system previously with a solid method begins to

consider changing to the compensated one, it is necessary a serious study of the overvoltages present in the

system. Besides, exist the necessity of change the connection rules of the system, this means that the users

have to connect only in a phase-phase way or three phase connection, this offers some advantages, since in

compensated system the phase to phase voltages are not critical affected by the ground faults.

In spite of the problems that represent the change in the grounding method, exist several advantage associated

to the compensated system, such as:

• Reduction in the magnitude of the ground fault current, therefore, a reduction in the touch and step

voltages, which means an improvement in the security conditions for the technical staff and people

• Improvement in the quality of services index, such as SAIDI and SAIFI

The following sections present the case of a Brazilian DSO, who has begun to analyze and implement a

compensated grounded method in few substations in order to explore the benefits associated with this sort of

grounded method, the main features of the project is presented in the paper of Silveira et al [37].

3.4.1. Motivations to change the actual grounding method in AES Sul network

AES Sul is a DSO that work from 1997 in the southern region of Brazil, this DSO has more than 1.2 million

users dispersed in 118 cities in the state of Rio Grande do Sul, the MV networks are principally constituted by

overhead lines suspended by wood and concrete poles, and 82 substation, the networks manage two

operating voltages, 13.8 and 23 kV. The solid grounded method followed by AES Sul cause grounded faults

with magnitudes roughly tens of thousands of amperes, which is enough to seriously damage a MV busbar in

their primary substations.

Additionally, the protection system used is based on overcurrent protection devices, therefore, in the present

of high fault resistance, the magnitude of the faulted current may not reach the setting values of the protection

function that make to trip the switching device associated to it [37].

The effect of a high fault resistance cause a loss in the sensitivity of the protection system used in the

distribution network, in the experience recorded by AES Sul, the high fault resistance is created when an

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overhead wire broke and fall in the asphalt, the fault current is very small that the protection system do not

recognize it as an earth fault [37].

The security issues in the network operation has gained a remarkable importance in the Brazilian DSO since

the deadly accidents occurred in their networks, the Brazilian Distribution Utilities Association (ABRADEE)

registered 29 deaths around the country related to wires broken and energized (fallen down in the street) in

the 2011 year. The distribution network of AES Sul is also facing accidents which cause injuries in people

(even deadly accidents). It is worth to mention that the lack of sensitivity of the overcurrent protection in

presence of high fault resistance has occasioned serious accidents in the technical staff in charge of the

corrective maintenance of the networks, in March 2012 AES Sul registered one of this kind of situation where

the overcurrent protection was not be able to the detect a ground since the high fault resistance, in this accident

the maintenance team found a broken MV wire (bar overhead line), this broke line was burning in the asphalt

since the overcurrent protection was not sensitive enough for the small fault current, meanwhile one of the two

linemen started to open the fuses the other was near the maintenance vehicle, in the opening of the second

fuse, accidentally the electrician produced an earth fault, breaking the energized line on the vehicle that was

under the line, since the other lineman was in contact with the car, he suffered a fatal medium voltage

discharge. The above-mentioned accident is an example of the accidents occurred in the network of AES Sul,

this type of accident affect to all of Brazilian DSOs [37].

In figure 3.43 is depicted a scheme of the fault currents and potential gradient produced by the ground faults,

this situation is also known as reverse earth fault, the fault current returns by the delta of the forward distribution

transformer windings, the fault impedance may increase since it is added the transformer impedance

(windings), another problem is the appearance of potential gradient, which are very dangerous for people in

the proximity of the fault [37].

Figure 3.43 (AES Sul – Scheme of reverse earth fault [37])

This type of accidents has shown the weakness of the overcurrent protection approach, since in the presence

of high fault resistance there is a lack of sensitivity, and as a consequence, the reliability of the protection is

seriously decreased. However, the more important aspect is related with the security issues, the accidents that

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have affected people and technical staff. Additionally, the Brazilian regulatory agency (ANEEL) has encourage

to the DSO to improve their indices such as SAIDI. The initial studies develop by AES Sul indicated that roughly

39% of the SAIDI was linked with the transient causes such as lightning, touch of trees in the distribution lines

and insulation issues in the network. An additional conclusion was about the fault in the medium voltages

system, 63% of cases were linked with transient issues mentioned before [37].

In base of the aforementioned accidents occurred in the distribution network, AES Sul started to consider a

different approach in the treatment of the ground faults. Therefore, in order to improve the reliability and safety

conditions of the system, it is considered a new approach of the grounding method, the resonant grounding

approach is now considered.

3.4.2. Resonant grounding method applied in the network of AES Sul

In 2009 AES Sul changed the solid grounded method towards a resonant grounding approach in only one

primary substation (Canudos Substation), and with that started the Resonant Grounding Project. After that, in

2012 the DSO installed a second system in the substation Novo Hamburgo 2.

The new approach of the grounding method is realized by means of the Ground Fault Neutralizer (GFN)

equipment, which is based on the Petersen Coil principle. The GFN is connected between the MV neutral

bushing of the power transformer and the ground. Figure 3.44 provides a scheme of the GFN system.

Figure 3.44 (AES Sul – Scheme of GFN system in the DN [37])

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The GFN consist of the arc suppression coil (Petersen coil), a residual current compensated inverter which is

in charge of reduce the fault current to a negligible value (almost zero), and a central processor named as

neutral manager (NM). The Petersen Coil is in resonance with the zero sequence capacitances, the AES Sul

network capacitances are in the range between 25 and 35 amps. The residual current compensator (RCC)

acts on the resistance component decreasing the ground current near to zero [37]. The GFN measures the

zero sequences admittance of the feeders in absent of fault conditions, the information about the feeders is

recorded in the NM and updated to give a continuous status of the grid, in the event of ground faults the GFN

measures again the zero sequences admittance of the feeders and compares them with the previous values,

the admittance of the healthy feeders remains the same, meanwhile for the faulty feeder is changed. . In sum,

the GFN solution aim to solve the ground fault problem restricting the flow of electrical power just to the positive

and negative sequence circuit [37, 65].

The GFN approach is faster than an overcurrent approach to extinguish ground faults since the GFN is able

to bring the fault current down to almost zero in less than 60 ms without tripping the faulted feeder. Regarding

the selectivity issues, the GFN provides a different approach since do not need the opening of the faulty feeder

because is able to inject a 180° current opposite through the neutral of the transformer and totally cancel out

the ground fault current, the continuity of service is kept as long as the DN is supplying phase to phase loads

or three phase loads. Concerning the reliability offer by the GFN, this system comes with its own back up

protection (feeder tripping) and is able to use the existing protection system as second back up.

The GFN system installed in the Canudos primary substation began operation with a 15 seconds time

limitation, after this time, the GFN system is switched to the backup protection for permanent faults. This

means, in case that the fault is transient, the GFN extinct the fault current and avoid the outage. On the

contrary, for permanent faults, the GFN is by passed to the backup protection and goes to the solid grounded

method, the overcurrent devices have to perform the protection action to clear the permanent fault, and of

course this means a disruption in the services for the user located downstream the fault location [37].

The time limitation of 15 seconds for the GFN operation is related with the overvoltages occurred in the

network. The Resonant grounded system (in the occurrence of one phase to ground conditions) presents

overvoltages in the healthy lines, typically this overvoltages increase is about 73%, this means that the phase

insulation of the system, previously sized to withstand the phase to ground voltage value (solid grounded),

currently supports the full value of the phase to phase voltage. This overvoltages affect to the entire insulation

of the network, especially to the surge arresters installed along the feeders, which are near to the user’s

transformers (MV/LV transformers). In this sense, it is evaluated the actions to correct and improve the network

due to the overvoltages problems generated by the new resonant grounded system. In order to overcome this

issue, AES Sul has started to evaluate the temporary overvoltages curve of the surge arresters that permit an

extension of the 15 seconds actually used by the GFN. The solutions needed has to be economical feasible

in order to justify its implementation [37].

92

3.4.3. Overvoltages issues in the resonant network

Canudos was the first substation where was implemented the resonant grounding method, this substation was

originally sized to work with a solidly grounded approach, therefore, the insulation of the substation and the

MV network connected to it, are not designed to support the overvoltages than can occur in an system with a

resonant grounded method. For this reason, GFN system that creates a resonant grounded network has a

maximum time period to extinguish the ground fault current, it has to be less than 15 seconds in order to avoid

irreversible damages in the insulation of the network components (transformer bushings, support insulators,

and cable insulation), since their primary components were maintained, it can be noted that the benefits of the

resonant grounded system are not fully reached because the time limitation [64].

In the case of the second substation (Novo Hamburgo) working with the resonant grounding, a permanent

operation mode of the resonant system is used. But, this required the changes of the actual surge arresters or

the implementation of alternative solutions. This solutions need to ensure the correct performance of the surge

arresters and the safety of the network. The new scheme of grounding means a significance increase in the

temporary overvoltages that will withstand the surge arrester in the network of Novo Hamburgo substation,

therefore, seems necessary to increase the rated voltage of the surge arrester, but the residual voltage that

can be presented for lightning discharge can damage the equipment protected by the surge arrester.

Therefore, it is necessary a tradeoff between the transitory overvoltages produced by the ground faults in the

health feeders and the correct value of the residual voltage in the arrester (produced by the atmospheric

discharge) [64].

Based on the aforementioned situation, in [64] it was proposed an alternative to overcome that problems. The

proposal is based on the utilization of series spark gaps for each surge arrester. The proposal represent an

economical savings in comparison with the complete replacement of the surge arrester, additionally, keeping

the actual surge arrester the residual voltage features is not changed. In figure 3.45 is presented the basic

scheme of the model used to simulate the performance of the surge arrester [64]

Figure 3.45 (AES Sul – Scheme of network to simulate the spark gap in the surge arrester [64])

93

4. Analysis of IEEE 34-bus feeder test network with solid grounded method and

introduction of the compensated grounded system

In the previous chapter was highlighted that the main driving forces to implement a compensated grounded

system are related to improvement in the quality of service and enhancements in security issues, the

compensated grounded system could be implemented by means of a Petersen coil, resistor, or a combination

of both. It is necessary to study the particular features, equipment, and loads of the distribution network in

order to design and size the compensation grounded scheme, besides and more important, it is needed to

take in consideration the existing grounded scheme of the system, their protections, and insulations levels.

The aim of this chapter consist on the analysis in steady state of IEEE 34-bus feeder test network, which is a

solid grounded system. The analysis in steady state constitute a first stage to determine the feasibility in the

implementation of a compensated grounded system. Therefore, it will be found the advantages and

disadvantages for introduction the compensation scheme in the previous solid grounded system.

The economic analysis to implement a compensation scheme in the IEEE 34-bus feeder test network is out of

scope since it is necessary to know the exact economic conditions of a electrical system such as the economic

regulation stated by the local authorities, or reward-penalty tariff scheme that justify the investment in the

network such as the change in the grounding scheme. The technical analysis for the implementation of the

compensated grounded system could be used as an input for the economic analysis.

The simulations of the IEEE 34-bus feeder test network will be developed with the sofware Digsilent Power

Factor in order to perform power flow, short circuit analyisis, overvoltage detection, and the implementation of

the protections of the network (in case of solid and compensated ground). Since the one phase to ground fault

has the greater probability of occurrence in a distribution network [30], it will be analysed the capacitive current

in the network for ground fault condition in order to decide the necessity of Petersen coil or resistance, the

reduction of the magnitude of the ground fault current, the limitations of the neutral overcurrent protection

scheme (50/51N) in the network, and the overvoltages presented underground faults with the respective impact

in the surge arresters. It is expected to find the main problems associated with the introduction of a

compensated grounded scheme since the test network is essentially a unbanlance system.

4.1. Description of the IEEE 34-bus feeder test network

The IEEE 34-bus feeder test network was created by the IEEE Distribution Test Feeder Working Group, the

distribution network has nominal voltage of 24.9 kV, which uses a solid grounded scheme, the system is

compounded by 34 bus bars (three phases and one phase), three phase and one phase feeder lines to

interconnect the nodes, the feeder lines have a considerable long lengths.

94

The distribution network supplies three phases, two phases and one phase loads connected along the network,

the loads are unbalanced since the system allow the connection of one phase loads. In order to overcome the

voltage drops caused by the length of feeders, there are two voltage regulators and two banks of capacitors

[71].

Figure 4.1 depicts the one line diagram of the IEEE 34-bus feeder test network, the system includes a power

transformer 24.9/4.16 kV (grounded wye-grounded wye connection) which is connected with a long feeder line

to supply a three phase load.

Figure 4.1 (IEEE 34-bus feeder test network [71])

In the annex 1 is presented the information regarding the details of feeder lines, the HV/MV power transformer,

MV/MV power transformer, voltage regulator, capacitor banks and the classification of loads connected to the

bus bars and along the feeder lines.

4.2. Design of the compensated grounded scheme

It is necessary to establish to main target of the compensated grounded scheme in order to choose the correct

combination of elements (Petersen coil, resistance, or a combination of both). In this sense, the two objective

to introduce a compensated scheme are the followings:

• Reduction of the ground fault magnitude, since the ground fault events have the greater probability of

occurrence [30].

• Improvement in the selectivity of the protection under the presence of fault resistance by means of a

directional ground protection.

The network under test is totally based on overhead conductors, there are not present medium voltage cables

to supply the loads. In this sense, the charging current in the network may be practically neglected.

95

Since there is not capacitive current to be compensated, it is not necessary the present of the Petersen coil to

compensate the capacitive current of the network. In order to prove that, the network has been simulated with

the 2.5 MVA power transformer with the secondary winding in open WYE in order to obtain the value of the

capacitive current contribution from the distribution network for the event of a ground fault in the bus 800 (LV

side of 2.5MVA transformer), figure 4.2 represents the network under test, equation 4.1 indicates the

expression to calculate the zero sequence currentBS.

Figure 4.2 (2.5MVA transformer wye open-capacitive current from the network)

Bo = CpqFjFjFjFjFodr (eq. 4.1)

Since the value of `M is very high in comparison with the other reactance, the value of the zero sequence

current (ground fault current) is considered neglected. Table 9 shows the values of the sequence reactance

for a ground fault in the bus 800 (LV side of 2.5 MVA power transformer) and the magnitude of the ground fault

current, the values were obtain in simulations for the two cases, open wye and grounded wye connection of

the 2.5 MVA power transformer.

Ground fault at bus 800

Open Wye (LV side Power

Transformer)

Grounded Wye (LV side Power

Transformer)

X0 (Ω) 6127 24,6

X1 (Ω) 21 21

X2 (Ω) 21 21

If abs (A) 8 711

Table 9 (Open wye vs Grounded wye, sequence reactance and ground fault magnitude)

96

According with the values obtained in the table 9 for the case of open wye connection in the power transformer

(LV side), the fault current to be provided by the distribution system (overhead lines) is practically negligible,

the `M capacitive reactance is very high in comparison with the other two sequence impedance, there is no

need of reactive compensation by means of Petersen coil. For the case of a ground fault in the bus 800 with a

grounded wye connection (power transformer LV side) the ground fault current magnitude has a considerable

value of 711 A, this current value represents a potential damage for the system.

Hence, the compensation scheme to be sized will be composed by just a resistor element, since the capacitive

fault current is practically negligible, which is consistent with an overhead line network without any medium

voltage cables. The resistor to be sized has to consider that will be permanently connected to the transformer

in normal system operation and will provide the compensation effect (reduction of ground fault current

magnitude) in the event of ground fault.

In the previous paragraphs have been indicated that the compensated system needs just to be a resistor, the

next step is about the calculation of the resistor value. It is necessary to considerer that the distribution network

under test is an unbalanced system, the unbalanced loads of the network produce a zero sequence voltage

and current, the zero sequence current will circulate through the resistor in normal operation condition and

consequently will exists losses associated to this operation.

In order to develop the directional grounded scheme and show its benefits regarding to improvements in the

selectivity, it has been chosen a restrained magnitude for the ground fault current of 50A, therefore, the value

of the compensated resistance should be calculated, and the power dissipated by the resistance should be

lower than the copper losses of the power transformer.

It is considered a ground fault in LV side of the main power transformer since beyond the bus bar 800 the

ground fault current magnitude is reduced by the impedance of the feeder, consequently, in the bus bar 800

will appear the greatest magnitude for ground fault.

The short circuit calculations performed by DigSilent employs the standard IEC 60909, which use a voltage

factor c of 1.1 to do the short circuit calculations. In the figure 4.3 appears the sequence circuit to be used to

calculate the value of the compensated resistance, it can be noted that the resistance appears in the zero

sequence circuit with the value of 3xRn, the equation 4.2 presents the variable Rn to be solved according with

the zero sequence current ( Io = ).

97

Figure 4.3 (Ground fault at bus bar 800 to obtain Rn for If 50A)

. √¡ ×

¢.£j:!j¤¤.¤! = S (eq. 4.2)

U = 320Ω (eq. 4.2)

The table 10 presents the value of Rn calculated from equation 4.2 and the associated magnitudes of interest

for power flow (normal operation condition) and ground fault event at bus 800.

Compensated Resistance

Rn (Ω)

Power Flow Simulations Short circuit Simulations

3xVo (kV)

3xIo (A)

P-resistor (kW)

3xIo=If (A)

320 9,87 11 34,77 50

Table 10 (Variables for power flow and short circuit for Rn 320 ohm)

For a ground fault current magnitude of 50 amps (in the bus bar 800) it is necessary to connect a resistor of

320 ohms. It was not considered the introduction of resistive fault since the condition above mentioned

constitute the worst condition, i.e. the greatest ground fault current magnitude obtained.

Additionally, the values of 3xVo and 3xIo obtained in the power flow simulation (normal operation condition)

are critically important to establish the threshold setting for the directional ground scheme presented in the

next section, this means that the ground directional protection scheme should not operate in normal condition

operation.

98

Even though it was obtained the desired ground fault current magnitude of 50 A, the residual voltages and the

power dissipated by the resistance are considerably high. Since the system supply monophasic loads the

value of the 3xVo should be kept low, and the power dissipated by the resistor (34.77 kW) is greater than the

power losses of the HV/MV power transformer. The resistance value of 320 ohms does not present a suitable

performance in normal operation.

Beside the reduction in the ground fault current magnitude, the value of the compensated resistance should

be considered the residual voltage and the power dissipated. It has been simulated power flows calculations

(unbalance power flow approach) for different values of compensated resistance Rn in order to obtain the zero

sequence voltage, zero sequence current at the LV side of the main power transformer, and the power

dissipated by the compensated resistance Rn. Additionally, was developed short circuit simulations to obtain

the ground fault current magnitude at the bus 800 (LV side main power transformer). The figure 4.4 indicates

the four variables whose magnitudes are presented in table 11 for the different values of Rn.

Figure 4.4 (Variables for power flow and short circuit for different values of Rn)


Rn (Ω)

Power Flow Simulations

Short circuit Simulations

(1Ph-Gnd fault at 800 bus)

3xVo (kV)

3xIo (A)

P-resistor (kW)

3xIo=If (A)

50 1,73 11,00 6,37 280

100 3,30 11,00 11,91 151

200 6,75 11,00 25,14 78

250 12,35 16,00 67,54 63

300 10,21 11,00 38,48 53

400 20,43 17,00 115,74 40

500 9,28 6,00 19,00 32

600 9,84 5,00 17,91 27

700 10,32 5,20 16,28 24

Table 11 (Variables for power flow and short circuit for different values of Rn)

99

It is expected that the value of the ground fault magnitude (3xIo = If) decreases with higher values of Rn,

nevertheless, when is employed a high value of Rn it is obtained a considerable increment in the residual

voltage (3xVo = Vn) for normal condition operation. According with the values of the table 11, it can be

observed that the residual voltage is very sensible to the increase in the value of the compensated resistance.

The resistance value to be chosen is 200 ohms since presents the lowest values for the 3xVo and 3xIo

magnitudes, and the ground fault current magnitude obtained with this resistance is 78 A, which is still a

considerable reduction in the ground fault current for the solid grounded scheme (711 A, table 9). Considered

that the energy released in a ground fault event is proportional to the square of the current magnitude (B3), it is obtained a reduction of 98.8 % in the energy released (1 − ©ª

©""), which is a worthy achievement to decrease

the risk in the network in the case of a ground fault event.

The increasing in the residual voltage is highly undesirable for a real unbalance distribution network since

there are single phase loads connected in the system, this is the main disadvantage of the compensated

approach for an unbalanced distribution networks, and one feasible solution is the use of three phases

connected loads with a delta connection. In the chapter 5 will be presented the test network with the

modifications of the load connection method in order to observe the enhancements in the residual voltage in

the system.

4.3. Limitation of the overcurrent protection approach

In this section is presented the limitations of the typical overcurrent protection approach for the short circuit

and ground fault events (50/51 and 50/51N schemes) used in solid grounded distribution system in the

presence of fault resistance. Commonly, in distribution networks the relays are associated with a switching

devices such as a recloser in order to perform a reclosing cycling to clear faults in case of temporary events

(one phase to ground fault), in any case there is a time coordination among the relays allocated along the

feeder in order to clear faults in a selectivity way.

Figure 4.5 shows the location of the overcurrent relays in the test feeder network, there are three zones of

protection (S1, S2, and S3) with their respective overcurrent relays, which are expected to clear downstream

fault according with their location. The settings of the relays has been selected to guarantee an adequate

coordination among them.

100

Figure 4.5 (Overcurrent protection scheme)

The settings for the short circuit and ground fault protections are presented in table 12. In annex 2 are

presented time overcurrent curves of the relays and their response for the events of short circuit and ground

fault without the presence of fault resistance (for a solid grounded system).

Overcurrent Short Circuit 50/51 Overcurrent Ground Fault 50/51N

Relay R Sector 1 R Sector 2 R Sector 3 R Sector 1 R Sector 2 R Sector 3

Operating Current Iop (A) 50/51 Residual Current 3xIo (A) 50/51N

46 45 27

5 7 7

Characterisitc ANSI/IEE

E Inverse

ANSI/IEEE Inverse

ANSI/IEEE Inverse

ANSI/IEEE Inverse

ANSI/IEEE Inverse

ANSI/IEEE Inverse

Current Setting (A) 88 70 40 40 30 20

Time Dial 1,8 1 1 1,5 1 0,9

Time Shift 1 1 1 1 1 1

Table 12 (Setting for relays 50/51 and 50/51N, Sectors 1, 2, and 3)

As seen in the table 12, the settings of the ground overcurrent relays take in consideration the zero sequence

current, which is mainly caused by the unbalance of the system, the ground protection is expected to allow the

unbalance power flow in the system for a normal operation condition.

Additionally, the setting of the ground overcurrent relays considerer the downstream fuses for coordination

purposes, the fuse should operate slower than the ground relay, in order to achieve coordination a common

practice consist on to set ground relay pick up time-current settings identical to phase relays, however, the

consequence of this practice is a loss of sensitivity for ground faults [6].

101

Hence, it is necessary a tradeoff of between a proper coordination (ground overcurrent relays vs fuses) and

the required sensitivity to detect the minimum ground fault current magnitude. The problems related to

sensitivity for ground overcurrent relays are increased with the presence of fault resistance, which reduces the

value of the ground fault current magnitude and affecting the performance of the ground relay. In order to

illustrate the problems associated with the presence of fault resistance (500 ohms), the figure 4.6 indicates the

response time of the ground relays shown in the table 12 (figure 4.5).

Figure 4.6 (Time overcurrent curves – ground fault at bus 848 with a fault resistance 500Ω)

In presence of fault resistance of 500Ω the ground fault current is equal to 28 amps as seen in the figure 4.6,

the relay sector 3 acts with a delay of 7.6 seconds, and there is not back up protection provided by the upstream

relays, which is considered a very dangerous situation for the entire distribution system integrity, the team

operators and public in general.

4.4. Introduction of the grounded directional protection

The lacks of a proper clearance of ground faults might produce serious accidents to the public, for the case of

distribution feeders with overhead conductors the situation is even more dangerous, since the conductors may

fall down to the ground and easily can cause damage towards the people as reported in [37]. The fault

resistance involved in a ground fault event decreases the sensitivity of the overcurrent approach, this is one

of the main reason to find out an alternative protection scheme that allow to recognize the ground fault even

in the presence of high values of fault resistance.

102

To overcome the problem of the decreased sensitivity caused by the fault resistance, it can be considered the

employ of the ground directional approach (ANSI code 67N), the ground directional approach employs the

relative position of the zero sequence voltage (3xVo) with respect to ground fault current (3xIo), the polarization

quantity will be the zero sequence voltage. The relative position of between the zero sequence vectors (angle

formed by them) will be analyzed with the compensated scheme (resistance Rn of 200Ω). Figure 4.7 presents

the vector diagrams of the zero sequences quantities for a ground fault in the bus 802, meanwhile figure 4.8

presents the case for a fault in bus 848. The two vector diagram have been obtained in the simulations without

considering a fault resistance as a first step. After establishing the settings of the ground directional protection

the performance of this protection will be simulated including a fault resistance in the ground fault in order to

check the gain in the sensitivity.

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)

103

The fault in the bus bar 848 was considered since this bus bar is very far from the main substation, it is

important to realize that the relative position of the zero sequences voltage and current has not changed

drastically for the two ground fault cases (figure 4.7 and figure 4.8), the position of the ground fault current

oscillate in a defined sector.

The above mentioned consideration helps to establish the tripping zone of the ground directional protection

since we can identify clearly where will be located the ground fault current with respect to the polarization

quantity 3xVo. Every relay has its particular way to define the tripping area for the directional protection, in the

case of DigSilent the directional relay sees the polarization quantity in opposite way as measured, the figure

4.9 presents the tripping zone (green hatched area) of the ground directional protection considering the above

mentioned particularity.

Figure 4.9 (Tripping zone of the ground directional relay)

The directional protection considerer a minimum threshold for the ground fault current to be clear by the

protection system, the setting for the ground fault current (minimum threshold) has to considered the maximum

unbalance current in the feeder (i.e. the zero sequence current 3xIo, correspond to a value of 11 amps for

relay sector 1) in normal operation conditions. Since the distribution network under test is an unbalanced load

system, there is a limitation produced by the zero sequence current 3xIo, nevertheless, the gain in the

sensitivity obtained by the ground directional approach is worthy.

It is necessary to calculate the maximum fault resistance that the ground directional protection is capable to

recognize as a fault event (i.e. maximum fault resistance that does not affect the sensitivity of the protection).

To do that, in the figure 4.10 is depicted the sequence circuits for a ground fault in the bus 848 (farthest bus

bar from the substation) with the introduction of fault resistance as a variable to be obtained. The sequence

impedance and resistance values (zero, positive, and negative) are seen from the bus 848 towards the

upstream network (network equivalent in case of ground fault at bus 848 without fault resistance), which only

depend on the networks elements such as feeder configuration and compensated resistance (200 ohms).

104

The ground fault current magnitude presented in figure 4.10 is a value slightly higher than the minimum

threshold of the operating current 67N and 50N for sector 1 (12 amps), the value of the ground fault (If) considered is 12.5 ampsIf > I¬®¯°±²³¤©´!. The equation 4.3 presents the variable U to be solved according

with the zero sequence current ( Io = ) and considering the compensated resistance of 200 ohms.

Figure 4.10 (Ground fault at bus bar 848 to obtain Rf for If 12A)

. √¡ ×

¢¤©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)

105

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 R Sector 1 R Sector 2 R Sector 3

Tripping direction Forward Forward Forward

Residual Current 3xIo (A) normal condition

11 6 3,4

Pick up current primary side (A) 12 12 12

Time setting (msec) 650 450 250

Table 13a (Setting for relays 50N, Sectors 1, 2, and 3)




Operation sector angle (deg) 40 40 40

Operating current primary side (A) 12 12 12

Polarizing voltage primary side (V) 7000 7000 7000

Minimum residual voltage (V) Ground fault bus 848, Rf=1000Ω

8700 8700 8700

Maximum torque angle MTA (deg) 5 5 5

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

106

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.

107

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.

108

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.

109

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])

110

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.

Maximum Continuous

Operating Voltage MCOV (kV)

Duty cycle (kV)

Duty Class

BIL (kV)

Grounded System

15,3 18 Normal 141

Compensated System

19,5 24 Normal 162

Compensated System

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.

111

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)

112

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)

113

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.

Item Load ID Load variation

description Previous

Connection Present

Connection

Line to Line

Phases

Overhead line

added (km)

Conductor type

1 L860 Change only in the connection type

3 Ph Wye 3 Ph Delta w/o

changes 0 -



changes 0 -



changes 0 -

4 L802-806 Change only in the connection type


changes 0 -

5 L808-810 Line added 1 Ph Wye Phase-Phase

B-C 1,8 4 ACSR


A-C 15,2 4 ACSR


A-C 4 4 ACSR


1 Ph Wye Phase-Phase

A-B 0 -


A-B 0,8 4 ACSR



A-B 0 -



A-B 0 -


A-B 7 4 ACSR

13 L858-864 Line added 1 Ph Wye Phase-Phase A-B 0,5 4 ACSR


A-B 1,5 4 ACSR



A-B 0 -



changes 0 -



A-B 0 -

18 500 kVA Tr Change in the winding connection

Wye Wye Delta Wye - - -

Table 15 (Variations in the loads to improve the quality of service)

114

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)

115

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.


Rn (Ω)


3xVo (kV)

3xIo (A)

P-resistor (kW)

3xIo=If (A)

200 0,29 0,5 0,05 78

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.

116

Figure 5.6 (Vector diagram for Voltages, bus 800, load connections modified, Rn=400Ω)


Rn (Ω)


3xVo (kV)

3xIo (A)

P-resistor (kW)

3xIo=If (A)

400 0,59 0,5 0,09 39

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.

117

Figure 5.7 (Ground fault at bus bar 848 to obtain Rf for If 3 A)

. √¡ ×

¢"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.




Residual Current 3xIo (A) normal condition

0,5 0,5 0

Pick up current primary side (A) 2 2 2

Time setting (msec) 650 450 250

Table 18a (Setting for relays 50N, Sectors 1, 2, and 3, modified network, Rn 400 ohms)

118




Operation sector angle (deg) 40 40 40

Operating current primary side (A) 2 2 2

Polarizing voltage primary side (V) 3800 3800 3800

Minimum residual voltage (V)

Ground fault bus 848, Rf=4300Ω 3940 4040 4200

Maximum torque angle MTA (deg) 5 5 5

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.

119

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]:

120

• 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 M½½Nh½j\p¾p

¿ − 1À x100% (eq 5.1 [78])

PM\3 = ÂI Y\\\J − 1Ã x100% (eq 5.2 [78])

121

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 Transformer

Distribution Transformer

Inductance per length unit (uH/m) 1,3 1,3

Length (m) 1 0,5

Current rate-of-rise (kA) 20 20

Voltage Drop (kV) (Lpl*l*di/dt) 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.



Chopped Wave Withstand value CWW (kV) 165 138

Basic Impulse Insulation Level BIL (kV) 150 125

Table 20 (Insulated withstand value of transformer [79])



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).

122

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.

123

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.

124

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

125

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.

126

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 Phase Neutral Spacing

ID

ACSR ACSR

300 B A C N 1/0 1/0 500

301 B A C N #2 6/1 #2 6/1 500

302 A N #4 6/1 #4 6/1 510

303 B N #4 6/1 #4 6/1 510

304 B N #2 6/1 #2 6/1 510

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 ID-

500 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.

127

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

128

Line Segment Data

Node A Node B Length(km.) Config.

800 802 0,79 300

802 806 0,53 300

806 808 9,82 300

808 810 1,77 303

808 812 11,43 300

812 814 9,06 300

816 818 0,52 302

816 824 3,11 301

818 820 14,68 302

820 822 4,19 302

824 826 0,92 303

824 828 0,26 301

828 830 6,23 301

830 854 0,16 301

832 858 1,49 301

834 860 0,62 301

834 842 0,09 301

836 840 0,26 301

836 862 0,09 301

842 844 0,41 301

844 846 1,11 301

846 848 0,16 301

850 816 0,09 301

854 856 7,11 303

854 852 11,23 301

858 864 0,49 302

858 834 1,78 301

860 836 0,82 301

862 838 1,48 304

888 890 3,22 300

Table A1.4 (Line segment data [71])

Power Transformer Data

kVA kV-high kV-low R - % X - % Tap

changer

Substation: 2500 69 - D 24.9 -Gr. W

1 8 +/- 5%

XFM -1 500 24.9 - Gr.W

4.16 - Gr. W

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.

129

Spot Loads

Ph-1 Ph-2 Ph-3

Node 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

Total 344 224 344 224 359 229

Table A1.6 (Spot loads data [71])

Distributed Loads

Node Node Load Ph-1 Ph-2 Ph-3

A B Model kW kVAr kW kVAr kW kVAr

802 806 Y-PQ 0 0 30 15 25 14

808 810 Y-I 0 0 16 8 0 0

818 820 Y-Z 34 17 0 0 0 0

820 822 Y-PQ 135 70 0 0 0 0

816 824 D-I 0 0 5 2 0 0

824 826 Y-I 0 0 40 20 0 0

824 828 Y-PQ 0 0 0 0 4 2

828 830 Y-PQ 7 3 0 0 0 0

854 856 Y-PQ 0 0 4 2 0 0

832 858 D-Z 7 3 2 1 6 3

858 864 Y-PQ 2 1 0 0 0 0

858 834 D-PQ 4 2 15 8 13 7

834 860 D-Z 16 8 20 10 110 55

860 836 D-PQ 30 15 10 6 42 22

836 840 D-I 18 9 22 11 0 0

862 838 Y-PQ 0 0 28 14 0 0

842 844 Y-PQ 9 5 0 0 0 0

844 846 Y-PQ 0 0 25 12 20 11

846 848 Y-PQ 0 0 23 11 0 0

Total 262 133 240 120 220 114

Table A1.7 (Distributed loads data [71])

Shunt Capacitors

Ph-A Ph-B Ph-C

Node kVAr kVAr kVAr

844 100 100 100

848 150 150 150

Total 250 250 250

Table A1.8 (Capacitor bank data [71])

130

Regulator Data

Regulator ID: 1 Regulator ID: 2

Line Segment: 814 - 850 Line Segment: 852 - 832

Location: 814 Location: 852

Phases: A - B -C Phases: A - B -C

Connection: 3-Ph,LG Connection: 3-Ph,LG

Monitoring Phase: A-B-C Monitoring Phase: A-B-C

Bandwidth: 2.0 volts Bandwidth: 2.0 volts

PT Ratio: 120 PT Ratio: 120

Primary CT Rating: 100 Primary CT Rating: 100

Compensator Settings: Ph-A Ph-B Ph-C Compensator Settings: Ph-A Ph-B Ph-C

R - Setting: 2,7 2,7 2,7 R - Setting: 2,5 2,5 2,5

X - Setting: 1,6 1,6 1,6 X - Setting: 1,5 1,5 1,5

Volltage Level: 122 122 122 Volltage Level: 124 124 124

Table A1.9 (Voltage regulator data [71])

131

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.

132

Figure A2.2 (Time overcurrent curves – ground fault at bus 848)

133

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]

134

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 3.33 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]

135

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

136

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

137

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