ONTREI RAIPALAREAL TIME SIMULATION OF ACTIVE DISTRIBUTION NETWORKMaster of Science Thesis

Examiners: Professor PerttiJärventausta and University lecturerSami RepoExaminer and topic approved in theFaculty of Computing and ElectricalEngineering council meeting on 4May 2009

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TIIVISTELMÄTAMPEREEN TEKNILLINEN YLIOPISTOSähkötekniikan koulutusohjelmaRAIPALA, ONTREI: Aktiivisten sähkönjakeluverkkojen reaaliaikasimulointiDiplomityö, 111 sivua, 5 liitesivuaJoulukuu 2009Pääaine: SähkömarkkinatTarkastaja: Professori Pertti Järventausta, Yliopistonlehtori Sami RepoAvainsanat: Aktiivinen jakeluverkko, aktiivisen jakeluverkon hallinta, hajautettutuotanto, hajautetun tuotannon verkostovaikutukset, reaaliaika simulointi

Sähkönjakeluverkkojen tehtävänä on ollut perinteisesti toimia passiivisenavälivaiheena kantaverkon kautta pienjänniteverkkojen asiakkaille siirrettävällesähköenergialle. Tämä asetelma on nyt muuttumassa johtuen hajautetuntuotannon määrän voimakkaasta kasvusta. Hajautetuksi tuotannoksiluokitellaan tuotantoyksiköt, jotka pienen kokoluokkansa vuoksi ontaloudellisesti järkevämpää kytkeä jakeluverkkoon siirtoverkon sijasta.Hajautetulla tuotannolla on monia positiivisia vaikutuksia, mutta se tuomukanaan myös joukon uusia haasteita, kuten suojauksen sekoittaminen,jännitteiden liiallinen nousu, sekä vikavirtatasojen kasvaminen. Perinteisenpassiivisen verkonhallinnan mukainen ratkaisu näihin haasteisiin onverkostoinfrastruktuurin vahvistaminen. Tällainen lähestymistapa johtaakuitenkin kohtuuttoman suuriin kustannuksiin.

Perinteisessä passiivisessa verkonhallinnassa sovellettavat verratenkonservatiiviset mitoitusperiaatteet johtavat matalaan verkon käyttöasteeseen.Aktiivinen sähkönjakeluverkko perustuu samaan olemassa olevaanverkostoinfrastruktuuriin, mutta tässä konseptissa verkkoa käytetään tarkemminhyväksi. Korkeampi käyttöaste saavutetaan käyttämällä erilaisia verkonsäädettäviä resursseja, kuten tuotantoyksiköitä, ohjattavia kuormia, energiavarastoja, sekä loistehon kompensointilaitteita älykkäästi hyväksi. Näidenresurssien säätö perustuu tarkkaan reaaliaikaiseen kuvaan verkon tilasta, jokasaavutetaan kattavilla mittauksilla, kommunikaatioyhteyksillä ja kehittyneillätietojärjestelmillä. Soveltamalla aktiivisen verkonhallintaa voidaan tehokkaastiehkäistä hajautetun tuotannon aiheuttamia ongelmia ja samalla mahdollistaasuurempi tuotantokapasiteetti jakeluverkossa. Verkonhaltija voi hyötyä tästätaloudellisesti myymällä aktiivisen verkonhallinnan palvelua tuotantoyksiköidenrakentajille, jotka puolestaan palvelua ostamalla saavat luvan rakentaasuuremman tuotantokapasiteetin. Suuremman tuotantokapasiteetinmahdollistamisen lisäksi aktiivinen verkonhallinta pyrkii myös parantamaanjakelun luotettavuutta kehittyneempien suojausmenetelmien, nopeammanjakelun palauttamisen ja saarekekäytön avulla.

Jännitteennousuongelma mainitaan usein jopa kaikkein rajoittavimmaksiesteeksi hajautetun tuotannon määrän lisäämiselle. Tuotantoyksiköidenaiheuttamaa jännitteennousua voidaan kuitenkin tehokkaasti hillitä aktiivisenjännitteensäädön avulla. Tämä säätömenetelmä voi perustua joko paikallisiinmittauksiin ja ohjaukseen tai vaihtoehtoisesti keskitettyjen tietojärjestelmienavulla toteutettuun koordinoituun ohjaukseen. Koordinoidulla jännitteensäädölläpäästään parempiin tuloksiin, koska säädössä käytettäviä resursseja, kutenpäämuuntajan käämikytkintä, loistehon kompensointilaitteita ja tuotantoyksiköitä

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voidaan käyttää koko säädettävän verkon kannalta optimaalisemmin.Koordinoitu menetelmä edellyttää kuitenkin soveltuvia tietojärjestelmiä, sekätarpeeksi kattavia mittaus- ja kommunikaatiojärjestelyjä.

Sallittavaa hajautetun tuotannon määrä voidaan myös tehokkaasti kasvattaaaktiivisen tehonvirtausten hallinnan avulla. Tätä menetelmää voidaan käyttääsilmukoiduissa verkoissa tai verkoissa, joita syötetään kahden tai useammanpäämuuntajan kautta. Pohjimmainen idea tässä lähestymistavassa on se, ettäsallittavaa tuotantokapasiteettia ei arvioida perinteisesti käytetyn N-1 kriteerinmukaan. N-1 kriteerin mukaan mitoitettu tuotantokapasiteetti rajoitetaansuuruusluokaltaan sellaiseksi, että tuotantoyksiköt saavat suurimmanyksittäisen komponentin (esimerkiksi toinen päämuuntajista) vikaantuessakintoimia täydellä teholla kulutuksen ollessa minimissään. Verkon käyttöaste jäätällaiseen mitoitukseen perustuvan suunnittelun seurauksena verrattainmatalaksi, sillä N-1 kriteerin mukaiset komponenttien vikaantumiset saattavatolla todella harvinaisia. Käyttöastetta laskee myös se, että tuotannon huipunosuminen samaan hetkeen kulutuksen minimin kanssa saattaa olla hyvinharvinaisia varsinkin jos verkossa on vaihtelevaa tuotantoa (tuulivoima jaaurinkosähkö). Aktiivinen tehon virtausten hallinta pyrkii käyttämään tätä verkonkäyttämätöntä kapasiteettia sallimalla suuremman hajautetun tuotannonmäärän. Ääritilanteiden ilmetessä tuotantoyksiköiden tehoa joko rajoitetaan tainiitä kytketään tarpeen mukaan kokonaan irti verkosta. Tämän menetelmänkäyttö edellyttää tehonvirtausten mittauksia tietyissä verkon solmupisteissä,sekä tuotantoyksiköiden varustamista soveltuvilla kommunikaatioyhteyksillä.

Tässä työssä tarkasteltiin myös hajautetun tuotannon yhteydessä yleisimminilmeneviä suojausongelmia. Tarkastelut suoritettiin asettamalla oikeita releitäohjaamaan reaaliaikasimulaattorin (RTDS®) pyörittämässäjakeluverkkomallissa olevia katkaisijoita. RTDS kykenee suorittamaansimuloinnit reaaliaikaisesti, mikä mahdollistaa ulkoisten laitteiden kytkemisenosaksi simulointia. Tarkasteluissa ilmeni tietyissä tapauksissa sekäylivirtasuojauksen sokaistumis- että selektiivisyysongelmia, jotka oltaisikuitenkin voitu välttää huolellisella suojausasetteluiden suunnittelulla. Joissakinverkoissa suuntaamaton ylivirtasuojaus saattaa kuitenkin osoittautuariittämättömäksi, jolloin on syytä käyttää kehittyneempiä suojausmenetelmiäkuten suunnattuja ylivirtasuoja-, distanssi- ja differentiaalireleitä. Toinen tässätyössä tehty suojaustarkastelu liittyi tuotantoyksiköidensaarekkeenestosuojaukseen (LOM - suojaus). Lähes kaikki nykyisin käytössäolevat LOM - suojat perustuvat saarekealueen sisällä yleensä vallitsevastatuotannon ja kulutuksen (sekä pätö- että loistehon) välisestä epäbalanssistaaiheutuviin jännite ja taajuus poikkeamiin. On kuitenkin mahdollista etteiriittävää epäbalanssia ilmene, jolloin saarekesuojat eivät joko ollenkaanhavahdu tai niiden toiminta hidastuu merkittävästi. Tämä sokea alue määritettiinpätöteho- loistehoepäbalanssikoordinaatistossa käytetyimmille LOM - suojille.Tulokset osoittivat, että taajuuden muutosnopeus suojausfunktio (Rocof)paransi LOM - suojausta huomattavasti verrattuna perinteiseen taajuus- jajännitesuojaukseen. Tarkasteluissa havaittiin lisäksi, että saarekealueenkuormien jänniteriippuvuudella oli merkittävä vaikutus suojien sokeiden alueidenmuotoihin. Tulevaisuudessa hajautetuilta tuotantoyksiköiltä saatetaan vaatiakykyä kestää muualla verkossa tapahtuvien vikojen aiheuttamia syviäjännitekuoppia, mikä täytyy ottaa myös huomioon valittaessa sopivia LOM -suojauksen asetteluita.

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ABSTRACTTAMPERE UNIVERSITY OF TECHNOLOGYMaster’s Degree Programme in Electrical EngineeringRAIPALA, ONTREI: Real Time Simulation of Active Distribution NetworkMaster of Science Thesis, 111 pages, 5 Appendix pagesDecember 2009Major: Electricity marketsExaminer: Professor Pertti Järventausta, Dr. Tech. Sami RepoKeywords: Active distribution network, active network management, distributedgeneration, real-time simulation, Impacts of distributed generation

The role of distribution networks as a passive intermediate phase for theelectricity flowing from the transmission grid towards low voltage networks isnow changing due to the rapid growth of distributed generation (DG). DG hasmany positive effects but it also causes many new challenges such asprotection problems, voltage rise problems and rising fault levels. Reinforcingthe network infrastructure, which is the traditional way for solving these kinds ofproblems, leads to very high costs.

The fairly conservative dimensioning principles of distribution networks haveled to a low utilization rate of distribution networks. Active distribution networksare based on the same infrastructure, but in this concept the existing networksare used more precisely by intelligently utilizing the active resources like DGunits, controllable loads, energy storages and reactive power compensationequipment. The voltage rise problem, which can greatly restrict the allowableDG capacity, is effectively avoided by actively controlling the reactive powerflows with the help of certain active resources. The allowable DG capacity canbe remarkably increased by actively controlling the power flows by regulatingthe output power of the DG units in the supervised area when certain restrictingconditions occur. Active network management also strives to enhance thesupply reliability with the help of island operation, faster supply restoration andmore efficient protection system.

The most common protection problems caused by DG were also studied inthis thesis. This was done by setting real protective relays to control the circuitbreakers located in a network model that was run by a real time digital simulator(RTDS®). Some protection sensitivity and selectivity problems occurred in thesimulation studies which, however, could have been avoided by appropriateprotection settings. Non directional overcurrent protection, which was used inthe simulation studies of this thesis can, nevertheless be insufficient in somenetworks which then require more advanced protection schemes such asdistance and differential protection. The other simulation study of this thesisexamined the functioning of loss of mains (LOM) protection. Most of the LOMprotection methods are based on the power imbalance in the power islandwhich usually occurs when a network section becomes islanded. It is, however,possible that both active- and reactive power production match so closely withthe demand in the power island that LOM protection fails to detect islanding.The form of this blind area was determined for some of the most utilized LOMprotection schemes in the active- reactive power imbalance coordinate system.It was found out in these studies that the voltage dependency of the utilizedload models had a significant effect on the shapes of the blind areas.

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PREFACE

This thesis was written at the department of electrical energy engineering in TampereUniversity of Technology as a part of the EU co-funded ADINE (Active DistributionNetwork) project. The simulation studies of this thesis were done in cooperation withthe ABB Corporation which is a project partner in the ADINE project. ABB providedthe protective relays used in the simulation studies of this thesis and helped with theirconfiguration.

This thesis was reviewed by Professor Pertti Järventausta and University lecturerSami Repo who was also the supervisor of this thesis. I want to thank ProfessorJärventausta for reviewing this thesis and providing me this job. I also want to givespecial thanks to University lecturer Sami Repo for the skilful guidance and interestingconversations. I am also most grateful for the valuable help that I have received fromDr. Tech Kari Mäki concerning protection issues and problems with the RTDS. I alsowant to thank the ABB Corporation for providing the relays and especially Kai Hiiteläand Jari Vuorela from ABB for their precious help with the configuration of the IEDs. Iam also very thankful to Merja Teimonen, the secretary of the department of electricalenergy engineering, for her excellent support with all the bureaucracy issues. I wouldalso like thank all my colleagues from the department of electrical energy engineeringfor the pleasant work atmosphere.

Finally I would like to give special thanks to my parents for the valuable supportthroughout my studies and to my girlfriend Enni for helping me forget all work issuesoutside my workplace.

Tampere, 18th of November 2009

Ontrei RaipalaTammelan puistokatu 14-16 A 3733100 Tampere

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TABLE OF CONTENTS

1. Introduction .............................................................................................................. 12. Changing power system environment ........................................................................ 3

2.1. Present design of distribution networks........................................................... 32.1.1. Distribution network structure ........................................................ 62.1.2. Distribution network planning tools ............................................... 72.1.3. Distribution network operation and management tools ................... 72.1.4. Distribution network protection ...................................................... 9

2.2. Distributed generation ................................................................................. 122.2.1. Loss of mains protection .............................................................. 15

3. Impacts of Distributed Generation ........................................................................... 173.1. The impact of DG on voltage levels ............................................................. 183.2. The impact of DG on network protection ..................................................... 18

3.2.1. Protection blinding ....................................................................... 193.2.2. Selectivity problems ..................................................................... 213.2.3. Failed reclosing problems............................................................. 223.2.4. The influence of the DG unit type ................................................ 243.2.5. The influence of DG on earth fault protection............................... 25

3.3. Other impacts of DG ................................................................................... 263.3.1. Impact of DG on fault levels ........................................................ 273.3.2. Economical impacts ..................................................................... 27

4. ACTIVE DISTRIBUTION NETWORK ................................................................. 294.1. Distribution network planning ..................................................................... 30

4.1.1. New planning principles for distribution networks including DG ....... 314.1.2. New requirements for computerized network planning ................. 324.1.3. General protection planning procedure ......................................... 33

4.2. Connection requirements ............................................................................. 334.3. Ancillary services ........................................................................................ 36

4.3.1. Virtual power plant in the management of ancillary services ........ 374.4. Communication arrangements ..................................................................... 39

5. ACTIVE NETWORK MANAGEMENT............................................................. 415.1. Control hierarchy of distribution system ...................................................... 425.2. Protection system ........................................................................................ 43

5.2.1. Sectionalizing circuit breakers ...................................................... 435.2.2. Directional overcurrent protection scheme ................................... 445.2.3. Distance protection scheme .......................................................... 455.2.4. Differential protection scheme ..................................................... 465.2.5. Loss of mains protection methods ................................................ 475.2.6. ROCOF based LOM protection .................................................... 485.2.7. Communication between feeder and generator protection ............. 50

5.3. Automatic control system (decentralised) .................................................... 51

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5.3.1. Frequency control ........................................................................ 515.3.2. Active voltage control .................................................................. 545.3.3. Reactive power control of the DG units ........................................ 555.3.4. Power electronic compensation .................................................... 565.3.5. Load Control ................................................................................ 575.3.6. Production curtailment ................................................................. 59

5.4. Area control level (centralised) .................................................................... 595.4.1. Coordinated voltage control ......................................................... 595.4.2. Power flow management .............................................................. 615.4.3. Automatic network restoration ..................................................... 635.4.4. Island operation ............................................................................ 64

5.5. Network Reconfiguration ............................................................................ 665.5.1. Fault level management................................................................ 66

5.6. ANM automation systems ........................................................................... 705.6.1. SCADA ....................................................................................... 705.6.2. Distribution Management System................................................. 71

5.7. Examples and demos of active distribution networks ................................... 735.7.1. The Orkney Islands demo ............................................................. 735.7.2. The demos in the ADINE project ................................................. 755.7.3. The fault location application ....................................................... 76

5.8. The commercial issues of ANM................................................................... 775.9. The transition towards ANM ....................................................................... 77

6. the simulation environment and THE simulation models ......................................... 796.1. The distribution network model ................................................................... 816.2. The generator models .................................................................................. 82

6.2.1. The brushless excitation system ................................................... 826.2.2. Hydroelectric power plant model.................................................. 846.2.3. The reactive power control of the hydro power plant .................... 856.2.4. Diesel engine model ..................................................................... 86

6.4. The load models ........................................................................................... 886.5. The utilized IEDs and the amplifier ............................................................. 90

7. Simulation results and analysis ................................................................................ 917.1. Sensitivity and selectivity of an overcurrent relay ......................................... 91

7.1.1. Sensitivity tests ............................................................................ 917.1.2. Selectivity tests ............................................................................ 937.1.3. Selectivity tests when using a 10 MVA synchronous generator .... 947.1.4. Sensitivity tests when using a 10 MVA synchronous generator .... 95

7.2. LOM protection simulation case .................................................................. 977.2.1. The NDZ for over- and under frequency and voltage protection ....... 100

8. Conclusions .......................................................................................................... 108References ................................................................................................................ 112

Appendix 1: Smart grid vision of the EU ........................................................... 124

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Appendix 2: Communication in distribution networks ....................................... 125Appendix 3: The connection diagram of REF543 IED ....................................... 126Appendix 4: The connection diagram of the REF615 IED ................................. 127Appendix 5: Non-detection zones of LOM protection........................................ 128

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ABBREVIATIONS AND NOTATION

set Generator speed settingCos ref Reference power factorD Regulating power of the generatorfs System frequencyf frequencyH Generator inertia constantI CurrentIFault Fault currentIFeeder The current seen by the feeder relayP Real powerPG Real power generation of a feederPL Real power consumption in a feederPmeasured Measured real powerPset Real power output setting value of the generatorQ Reactive powerQref Reference reactive power settingR ResistanceUFault Voltage in the fault point just before the faultV Voltage

V Voltage rise, voltage changeX ReactanceZFault_b The impedance that consists of the impedance of the line

between the common feed point and the fault location andthe fault impedance

ZGen Represents the impedance between the common feed pointand the generator

ZNet The impedance that consist of the impedance of the linebetween the common feed point and the supply point andthe impedance of the supplying network

Zth Thevenin impedanceAMR Automatic Meter ReadingANM Active Network ManagementCB Circuit BreakerCFP Common Feed Point is the furthest location from the fault

which is yet fed parallel by the generation unit and thesupplying network

CT Current TransformerDMS Distribution Management System is a program used for

managing distribution network operation.DG Distributed Generation

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DDAC Digital to analog converter card in the RTDSDOPTO Digital optical isolation system card in the RTDSFRT Fault Ride ThroughFACTS Flexible Alternating Current Transmission SystemHV High voltageIED Intelligent Electronic Device which is a modern protective

relay.IGBT Insulated gate bipolar transistorLOM Loss of Mains refers to a situation where a part of the

network including generation is disconnected from the maingrid.

LV Low voltageMV Medium voltageNDZ Non Detection Zone, which refers to the generation –

demand equilibrium where the loss of mains protection of agenerator fails to operate properly.

NIS Network Information SystemPLC Programmable logic controllerROCOF Rate of Change of Frequency is a protection function meant

for islanding detection in distributed generation unitsRTDS Real Time Digital Simulator is powerful simulator that

enables the interaction studies between power systemmodels and actual physical devices

SCADA Supervisory Control and Data Acquisition is a programused for the monitoring and control of distributionnetworks.

SVC Static VAR Compensator is a fast acting power electronicdevice meant for reactive power compensation

STATCOM Static Synchronous Compensator is a fast acting powerelectronic device meant for reactive power compensation

TCR Thyristor controlled reactorTSC Thyristor switched capacitorVSC Voltage source converterVT Voltage Transformer

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1. INTRODUCTION

Environmental concerns and the rising prices of energy have led to a remarkablygrowing interest in renewable energy sources. Power generation units based onrenewable energy sources are often relatively small sized which makes it uneconomicalto connect these units to transmission networks. This is also true for small scalegeneration units based on conventional energy sources which are also regaining interestbecause of multiple reasons like modular structure, short lead times and smallerrequired capital investments. A steadily increasing amount of small generation units is,therefore, now being connected to distribution networks which have traditionallycontained very little generation if at all. [Jen 00]

The designing and operating of distribution networks have been fairly simplebecause of the unidirectional flow of power. This stems from the fact that all thegeneration units have traditionally been connected to transmission networks, whereas,the purpose of distribution networks has solely been to transfer the power flowing fromthe transmission networks to low voltage networks. The small scale distributedgeneration (DG) units are now changing the role of distribution networks andinvalidating the assumption of unidirectional power flow. This raises new challengeslike problems with protection, changing voltage profiles and rising fault levels. [Jen 00,Mäki 07a] The common solution to these problems is to reinforce the primary networkinfrastructure so that it is able to cope with all possible extreme conditions. This kind ofway of dimensioning distribution networks leads to a fairly low utilization rate of thenetwork since the dimensioning extreme conditions can be very rare [Rep 05b]. Thehigh costs related to this traditional way of managing distribution networks have raiseda question whether there would be a more reasonable network management concept.

Active distribution network concept is a new kind of approach for dealing with thechallenges raised by DG. There is no universally agreed definition for this concept atthe moment but some attributes regarding this concept appear to be common. The basicidea in this concept, however, is to respond to the future challenges raised by the growthof DG, increased demands on power quality and to maximize the use of network assets.Both EU and the USA have showed great interest for this intelligent network conceptand created their own visions of future networks [Eur 06, MGI 07]. The visions of thesetwo players seem to emphasize similar kinds of characteristics like flexibility (copingwith customer needs, growth of DG and other future challenges), accessibility to allparties, reliability (meeting increased requirements regarding supply reliability),economic efficiency (maximal utilization of assets) and resiliency (resilient to naturaldisasters and rapid supply restoration times).

The future network visions of EU [Eur 06] and USA [MGI 07], however,concentrate on describing the attributes that are desired but they do not give any answerhow this attributes are technologically achieved. This thesis, on the other hand, will

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concentrate on the technologies that enable the desired features of active distributionnetwork to be achieved. Some discussion concerning contractual and commercial issuesof this topic is also included but the emphasis will be on the technical perspective. Theactive network management (ANM) solutions presented in this thesis are based onselected conference papers and research reports. A picture illustrating the vision of EUsmart grid can be found from appendix 1.

This thesis surveys the most important challenges raised by DG and represents someapproaches for overcoming these challenges. The group of solutions for these variouschallenges are reviewed from the control hierarchy of distribution networks point ofview. The studies of this thesis will concentrate on medium voltage distributionnetworks because this part of the network is mostly affected by DG. It would have beeninteresting to include some discussion concerning the roles of intelligent transmissionnetworks and -low voltage networks (micro grids) but the massive scope of this researchfield necessitates the exclusion these issues. In order to better understand the attributesof active distribution network, the present structure and the common operation practicesof distribution networks will first be discussed in chapter two. The term DG and thereasons for the growth of DG are also discussed in the same chapter. After this, the mostsignificant impacts of DG on distribution networks are presented in chapter three.Active distribution network concept is introduced in chapter four and the way accordingto which it is managed, namely the active network management method, is discussed inchapter five. Simulation studies concerning protection problems caused by DG are alsoincluded in this thesis. Chapter six presents the real time simulation environment andthe simulation models used for these studies. The idea of the simulation cases and theresults obtained are presented in chapter seven. Finally, some conclusions are made inchapter eight.

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2. CHANGING POWER SYSTEM ENVIRONMENT

Power systems were originally designed in a fashion where small generating units werefeeding local loads through simple network infrastructure. The local networks were notinterconnected but they were simply built to connect the local loads and generators.Over the years the requirements to make the power system more efficient and moreeconomic, however, led to a more centralized power system structure. An extensivetransmission network was built that connected all the local distribution networks, andlarge power plants connected directly to this transmission grid began to replace thesmall generating units. Large generating units gradually replaced practically all thesmall scale units which led to a situation where all the generation was connected totransmission network. The role left for the distribution networks was solely to passivelytransfer the power flowing from the transmission network to the loads and low voltagenetwork connections distributed all over the distribution networks. Because the powerflow in these kinds of power systems is unidirectional, that is flowing from thetransmission grid to the distribution networks, the design and operation of distributionnetworks has been fairly simple. [Jen 00, Ple 03]

In the recent few decades there have been increased concerns over environmentalissues which have given more interest on renewable energy sources. Generating unitsbased on renewable energy sources are often connected to distribution networks becauseof their small size which usually renders a connection to transmission networkuneconomical. Also the fact that the location of renewable energy source basedgenerating units is dependent on the location of the primary energy source like a river ora windy area may sometimes necessitate the connection to distribution network becauseof the lack of nearby transmission network. Other types of small generating units basedon non-renewable energy sources have also gained ground lately because of theireconomical competence in the liberalized electricity market. The renewed interest insmall scale generation connected to distribution networks is changing the power systemstructure again and raising new challenges to the design and operation of distributionnetworks. [Jen 00, Ple 03]

2.1. Present design of distribution networks

This subchapter will briefly present the distribution system entity. Despite the brevity ofthis chapter, the topic is actually very broad and more extensive representation can for

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instance be found from [Lak 95] and [Lak 08]. This chapter is written from the Finnishnetwork design point of view.

The function of the distribution system entity is to deliver power flowing from thetransmission network and from the distributed generation units connected to thedistribution network to customers. Distribution system entity consists ofsubtransmission networks, HV/MV substations, distribution network, distributiontransformers, switching substations and low voltage network. In addition to theseprimary components, however, distribution entity also includes secondary componentsand systems like protection relays at the substations, fault indicators, instrumenttransformers and auxiliary voltage supplies. Control center information andmanagement systems are also examples of secondary systems. [Lak 08]

Distribution networks have a huge impact on power supply quality. About 90 % ofall the supply interruptions in Finnish power system are caused by faults in distributionnetwork. The voltage quality experienced by the customers is also mainly determined inthe distribution network level. This is because voltages in distribution networks arecontrolled only by altering the winding ratio of the HV/MV transformer(s) located at thesubstation. There are basically no devices actively controlling the voltages further in thenetwork. The winding ratio of the HV/MV transformer is changed by the On-load tapchanger (OLTC) which, respectively, is controlled by an automatic voltage controller(AVC) relay. [Lak 08]

The HV/MV substation is the most important single component in the distributionentity. A HV/MV Substation consists of the high voltage switchgear, one or severalMV/HV transformers, medium voltage switchgear and the auxiliary voltage supplies. Adistribution substation with a one HV/MV transformer is shown in Figure 2.1. Thecomponents marked as CT in the figure represent current transformers and the onesmarked with VT represent voltage transformers. They are meant for isolating themeasurement equipment from the HV components. [Lak 95, Lak 08]

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Figure 2.1. Layout of a simple one HV/MV distribution substation [Reproduced fromLak 95]

The MV busbar is located in the building in the figure. Each of the outgoing MVfeeders is connected to the MV busbar through a disconnector and a circuit breaker(CB). CBs are controlled by intelligent electronic devices (IED, which is a modernmicroprocessor based relay) which make their control decisions according to thecurrent- and sometimes also the voltage measurements. The feeder currents aremeasured by CTs situated at each outgoing feeder, whereas, the voltage is measuredfrom the MV busbar. [Lak 95, Lak 08]

The IEDs are equipped with overcurrent and earth fault detection functions as wellas with automatic reclosure function. Automatic reclosing is used for removingtemporary faults in the overhead lines. In practice this is accomplished by opening theCB protecting the feeder in question for a short predefined period of time. CBs can alsobe used along the feeder lines but this has been rare in Finnish networks. [Lak 08] Thelast few years have, however, been showing a growing trend towards installing CBsalong the feeders as well.

MV Disconnectors can used for changing the network topology by opening andclosing them in a desired way. They can be either manually controlled by field crews oralternatively remotely from the control center if remote controlled disconnectors areused. Remote controlled disconnectors are particularly beneficial for isolating thefaulted part of the network after a fault because they can be switched on and offremarkably faster than manually controlled switches. Remote controlled switches are,on the other hand, more costly compared the manually controlled ones and it is,therefore, not usually economically justified to make all disconnectors remotelycontrolled. The utilization of remote controlled switches does not reduce the number ofsupply interruptions but only shortens the interruption time. This is because

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disconnectors are generally not capable of breaking fault current although load breakingdisconnectors enable breaking up to some 630 A (SF6 disconnectors). CBs, on thecontrary, do reduce also the number of interruptions because of their ability to break thefault current up to a designed value. [Lak 95, Lak 08]

2.1.1. Distribution network structure

Distribution networks are almost without an exception operated in radial mode althoughthey are often built in open ring or partially meshed structure. Open ring structuremeans that two feeders connected to each other from their line ends are separated by aswitch during normal operation. This switch can, of course, be closed when back upsupply to the other feeder is needed. The same fashion is also often used on feeders builtbetween two HV/MV substations, that is, a switch connecting a feeder fed by onesubstation to another substation is kept open from the other end during normaloperation. The supply of this feeder can then be very rapidly switched to the othersubstation, for instance, during the maintenance of the other substation. Figure 2.2illustrates this kind of network structures. On the left there are two feeders fed from thesame substation that are separated by a open switch from the middle during normaloperation, whereas, on the right there is a feeder that is normally fed from substation 1but whose supply can be changed to substation 2.

Figure 2.2. Distribution network operating structures

The benefits of radial network structure compared to ring or meshed networks aresimpler protection design, smaller fault levels and easier voltage profile control. [Lak95] Meshed networks, on the other hand, are better compared to radial networks in thesense that the losses are smaller in meshed networks and the voltage drops are less of aproblem. [Lak 08]

7

2.1.2. Distribution network planning tools

Distribution network planning is typically carried out with the help of dedicatedplanning software which is called network information system (NIS). In Nordicthinking, a typical NIS includes network component data and plenty of calculationfunctionalities combined to a graphical interface. A NIS usually shows the geographicalimage of the area in question on the background to help the planning engineers tovisualize the network area better. The ability to analyze both technical and economicalaspects of network planning is an essential feature of NIS. [Mäk 07d] Figure 2.3represents typical functionalities of a modern NIS according to Nordic thinking.

Figure 2.3.Functionalities of a modern network information system [Mäk 08]

As it can be seen from the figure, NIS can be used for plenty of various purposes suchas network documentation and condition monitoring. NIS is also used for manyplanning tasks such as planning network configuration, investment planning andconstruction planning. The network calculations in NIS are based on steady statecalculations and rms values. [Mäk 08]

2.1.3. Distribution network operation and management tools

The SCADA (System Control and Data Acquisition) system is used for collectinginformation from the network to the control center and for the remote control andsupervision of various network devices. The databases of SCADA provide specificinformation and graphic overviews concerning HV/MV substations and the relatedequipment. SCADA does, however, not contain specific information concerning theMV or LV networks and their components. The main tasks of SCADA are event

8

information management, network topology management, remote control of variousdevices, remote measurements, remote settings and reporting. The event data providesinformation from the status of IEDs, fault indicators, switches and OLTCs. The status ofremote controlled switches is automatically updated to SCADA but the status ofmanually controlled has to be manually updated. With the help of the remote settingfeature the protection settings of the IEDs can be changed from the control center.SCADA can also alert the control engineers in case of circuit overloads, network faultsor device malfunctions. [Lak 95, Lak 08]

The idea of DMS (Distribution Management System) is to provide useful networkoperation support tools and a graphical overview of the whole controlled network to thenetwork control engineers. The main difference to SCADA system is that DMS containsmyriad analysis and support features. Figure 2.4 represents the functionalities of atypical DMS. The figure also shows the linkages of DMS to other information systems.As the figure illustrates, DMS is founded on the combined information from networkdatabase and process data from SCADA. [Ver 97]

Figure 2.4. Functionalities of a typical distribution management system and its linkagesto other systems [Ver 06]

DMS provides many useful support functionalities. The system has calculationfunctions based on real time data from the distribution process that provide a valuabletool for supervising the network as well as for planning and simulating changes in thenetwork topology. DMS also assists in fault management by means of fault location,supply restoration, customer trouble call management and fault reporting. Field crew-,topology- and configuration management tools are also included in DMS. [Ver 06]

9

2.1.4. Distribution network protection

Protective devices are required to ensure safe operation and to minimize the damagecaused by possible fault conditions. Faults can cause serious damage to networkcomponents and endanger human lives and it is, therefore, a necessity that protectivedevices are very reliable and have rapid operation times. These devices must besensitive enough to detect and remove all possible faults and yet they must also beselective enough not to operate on any normal operation conditions. This operationphilosophy of network protection is illustrated in table 2.1. It is also essential that onlythe faulted part of the network is disconnected as a result of a fault so that the number ofcustomers experiencing an interruption of supply is minimal. The last mentioned is alsoknown as the selectivity of protection. [Lak 95]

Table 2.1. The operation philosophy of protective relays

In order achieve sufficient protection sensitivity and selectivity, the protection planningengineers need knowledge concerning many factors. Such factors include the maximumload currents, maximum and minimum fault currents and the nominal currents and shortcircuit current durabilities of conductors and other network components. It is alsoimportant to bear in mind that changes in the network configuration can decrease thefault current. [ABB 00] It is, however, possible to remotely change the settings ofmodern IEDs which is very useful in cases when changes in the network configurationrender the normal protection settings unworkable. Usually such secondary settings areplanned beforehand so that the new settings can rapidly be applied when they areneeded.

One of the main reasons for the radial design of distribution networks is thesimplicity and low cost of overcurrent protection. [Dug 01] The easiest way to achieveselectivity of the overcurrent protection in radial networks is the use of time selectivity.Time selectivity can be based on definite time delay or inverse time delaycharacteristics. Time selectivity is sufficient in radial network, whereas, for ringnetworks the relays will have to be equipped with the ability to detect the direction ofthe current. [Lak 95] Selectivity can also be achieved by using time- and currentselectivity, time- and direction selectivity, current- and impedance selectivity,interlocking, differential protection and distance protection. [ABB 00]

10

Time selectivity is based on setting appropriate grading times. This means thatappropriate operation delays are set for sequential relays in such a way that the relayclosest to the fault point always trips first. The coordination of overcurrent protection inradial network is illustrated in figure 2.5. The circles marked with 6, 7 and 8 representdifferent fault points along feeder 1. When, for example, a short circuit occurs at the endof the feeder (at point 8), the fault current seen by relays one (feeder relay) and two(supply point relay) settles at the level which is marked with an 8 in the time- currentcoordinate system of figure 2.5. This current magnitude is within the operation area ofboth relay one and relay two. This means that an appropriate grading margin must be setbetween the two relays in order to ensure selective operation. Relay one will, however,operate first as it can be seen from the time-current curves of the two relays (see thecurves marked with numbers 1 and 2 in figure 2.5). Relay two would, however, alsooperate after the grading margin time if relay one failed to operate for some reason. Thisprovides a natural back up protection for feeder one. The operate time of the supplyrelay has to be slow enough so that the feeder relay always operates first but, on theother hand, fast enough so that no components should be damaged. Grading timeconsists from factors such as the operation time tolerance of the relay, the operationtime of the controlled circuit breaker, retardation time of the relay (the time margin thatdetermines how early before the upcoming tripping does the relay need to return tonormal state for the cancellation of the tripping command) and safety margin. [ABB 00]

Figure 2.5. Relay coordination example [ABB 00]

11

For the successful utilization of overcurrent protection, it is a necessity that there is anappropriately large difference between the maximum load current and the minimumfault current. Otherwise it could not be guaranteed that overcurrent protection detects allfaults and yet does not cause unwanted tripping. Therefore, other measures such asnetwork reinforcements need to be carried out if the margin between the maximum loadcurrent and minimum fault current is not large enough. When this margin is largeenough, however, the tripping threshold for the current is chosen from somewherewithin this margin. Factors such as the starting currents of motors and transformerinrush currents can increase the maximum load current which has to be taken intoaccount when choosing the tripping current settings [ABB 00].

Protection selectivity on a radial feeder containing sequential relays is alsoillustrated in figure 2.6. The longest protection delay time is set to the supply relay andthe shortest to the relay furthest from the supply. If a fault occurred at point B in thefigure, the main and the feeder relays would detect the fault current and start counting,but only the feeder relay tripped because its delay time (0.3 seconds) is shorter than thedelay time of the main relay (0.5 seconds). Respectively, if a fault now occurred at pointA, only the main relay would detect the fault current and trip after 0.5 seconds. [You90] In reality, however, there would likely be multiple current setting stages (low stageand high stage at least) if modern IEDs were utilized. The current threshold setting ofthe high stage protection is commonly set considerably higher compared to the lowstage setting so that the high stage protection only trips when a fault occurs close to theIED in question. The delay time for high stage setting can thus be set much shortercompared to the low stage setting without losing selectivity of the protection. Thus,when a fault occurred at point A, the fault would quite likely have been cleared fasterthan 0.5 seconds by the high stage setting of the IED.

Figure 2.6. Setting protection delays for sequential relays [You 90]

12

The protection times could also be speed up without losing selectivity by usinginterlocking. In the case of a fault at point B (figure 2.6), the feeder relay would send arestraint signal to the main relay. The feeder relay, however, would not receive arestraint signal from the branch relay. The feeder relay would thus understand that it isthe closest relay to the fault and were to trip instantly without any further delay.Respectively, in the case of a fault at point A, the main relay would detect the faultcurrent but were not to receive a restraint signal from downstream relays. The mainrelay could thus trip instantly without delay. Some time would, of course be required forsending and receiving the signals. [You 90]

2.2. Distributed generation

In the recent years there has been a growing interest for connecting small scalegeneration units into the distribution networks. Terms like distributed generation (DG),embedded generation, dispersed generation and decentralized generation are often usedwhen discussing of these small units. There is, however, no consensus for an exactdefinition for these terms. Many different characteristics of the generating unit likebeing non-dispatched, being run by a renewable energy source, being connected tomedium voltage network, having a generation capacity within certain limits, beingsituated close to loads and so forth have been used by different parties to define what isDG. [Pep 05]

The generation capacity is often used for distinguishing what is DG and what is not.There, however, seems to be no consensus on this definition base either. The CIGRÉ(The International Conference on Large High Voltage Electric Systems) defines DGsimply as generation unit with a capacity of lower than 50-100 MW [Ack 01, Pep 05].The EPRI (Electric Power Research Institute), in turn, categorizes the generationcapacity range of DG as from few kWs to 50 MW [Ack 01]. The reference [Ack 01]prefers an even more broad capacity range, namely from few kWs to roughly 300 MWbut finds that it is practical to have four different DG size categories. These are:

Micro ~1 W to 5 kWSmall 5 kW to 5 MWMedium 5 MW to 50 MWLarge 50 MW to 300 MW

Most parties, however, do agree that DG is electrical generation connected todistribution networks. [Pep 05] Because there is no clear consensus on the definition ofDG, a very broad definition for DG by [Ack 01] will be used in this thesis. Thisdefinition defines DG as electrical power generation connected directly to distributionnetwork or on the customer side of the network.

Most distributed generators are based on traditional ways of energy production suchas diesel, combustion turbine, combined cycle or other rotating machinery. DG

13

concept, however, also includes renewable energy sources such as photovoltaic, windturbines, fuel cells, and hydro generation. [Wil 00, Bar 00] Table 2.2 shows some of themost common types of DG and their typical capacity ranges. The installation andoperation costs as well as some other information can also be found for each technologyfrom the table. Wind power and photovoltaic (PV) have low availability because theycannot be guaranteed to produce power when needed. This stems from the natural factthat it is not always windy and the sun does not always shine.

Table 2.2. Distributed generation technologies [Häg 03]

DG units often have very different characteristics compared to large conventional powerplants. Conventional plants and large size DG units use synchronous generators(permanent magnet- and separately excited) that are able to control their reactive poweroutput. Small and medium scale DG units, however, often use induction generatorsinstead of synchronous generators because of the lower price of induction generators.Unlike synchronous generators, induction generators are not capable of feeding reactivepower to the grid. They actually need reactive power from the grid both during theirstart up and operation. Some DG units like photovoltaic and fuel cells generate DCcurrent and, therefore, require a converter. [Ack 01]

The attractiveness of the small distributed generation resources is based on manyfactors. CIRED (The International Conference on Electricity Distribution Networks)and CIGRE (The International Conference on Large High Voltage Electric Systems)surveyed and studied the drivers encouraging the adaptation of embedded generation.The results of these two can be seen in table 2.3. The CIRED survey concentrated onpolitical drivers, whereas, the CIGRE report had its emphasis on commercialconsiderations. One of the commercial drivers according to CIGRE is the possibility of

14

achieving cost savings through reduced grid fees (transmission costs) if DG units aresituated close to loads. DG units situated at suitable locations also have the beneficialeffect that MV network losses are usually reduced [Rep 08]. This is also a clearfinancial benefit for the network utilities although the monetary value of the savingachieved through the reduced grid fees is much more significant [Rep 06]. The MVnetwork losses may, however, also increase if a large DG unit is connected to a locationwhich is far from consumption points. [Rep 08] The statement that it is easier to findsites for DG may not always be true either. Sometimes it can be very challenging to finda suitable site for wind turbines or a landfill gas plant because of the public resistance.[Pep 05] One could also ask whether it really is easier to find sites for large amounts ofDG units with the aim of building an aggregated generation capacity of 1000MW oralternatively building one large 1000MW rated conventional power plant.

Table 2.3. Drivers encouraging the use of embedded generation [Cir 99, Pet 97 see Jen00]

Political drivers according to CIRED Drivers according to the CIGRE reportReduction in gaseous emissions Availability of modular generating plantDiversification of energy resources Ease of finding sites for smaller generators

Deregulation or competition policyShort construction times and lower capitalcosts

Energy efficiency or rational use ofenergy

Generators may be situated closer to loads,which may reduce transmission costs

National power requirement

Renewable energy based DG units could also be beneficial in the management of risksrelated to energy price. A farmer, for instance, can secure a certain share of his energycosts in the long term by constructing a few wind turbines or bio gas poweredgenerating units. The higher the share that electricity costs represent of the totalproduction costs, the more justified it is to manage this risk. Certain types of DG unitscan also be very effective when combined to production plants. For instance, CHPbased DG units are often the most reasonable way of using waste byproducts insawmills and some other processing industry units.

The climate policy of the EU has and is also encouraging the use of DG. In order tomitigate climate change, the EU has set a target of producing 21 % of its electricity withrenewable energy sources by 2010 (directive 2001/77/EC) [Eur 09a]. This, however,was not a binding target and it is unlikely that the target will be reached by 2010. TheEU, nevertheless, also has issued a binding target in the “Renewable Energy Roadmap”which states that 20 % of the total energy consumption in the EU has to come fromrenewable energy sources by 2020 [Eur 09b]. Renewable energy source based powerplants are dependent on the primary energy source like wind, and must, therefore, beconstructed on sites where the circumstances are favourable. These sites are often

15

located in rural areas where the only connection to electric power system is through ofsomewhat weak distribution network. [Jen 00]

DG units are rarely utilized for supporting the power system at present. They arerather considered as passive generators producing energy whenever they can not takingany part in the other functions of the power system such as voltage control, networkreliability, generation reserve capacity and so on. This is mostly because of theadministrative barriers and only partly because of the technical features of DG units.[Jen 00] There, however, now seems to be a trend towards demanding similarrequirements from DG as from central power plants [Rau 08].

2.2.1. Loss of mains protection

According to the present common practice, DG units are not allowed continue feedingunintentionally islanded network sections (power islands). A power island can, forinstance, be formed as a result of the operation of a feeder relay which controls the CBprotecting a feeder to be opened. Unintended islanding is not tolerated for a number ofreasons. Probably the most serious reason for this is that unintended islanding poses asecurity risk for the utility personnel by re-energizing the lines that should be de-energized for repair or maintenance purposes. The islanding situations may also causeauto-reclosing failures by back feeding the lines and thereby maintaining the fault arcthat would otherwise be extinguished by the autoreclosure. The fact that the DG unititself, as well as the CB performing the autoreclosure, may be damaged as a result of anout-of-phase reclosing is also one of the main reasons for the non-acceptance ofislanding. There is also a risk that the customer devices may be damaged due to the poorpower quality in an island zone. Because of these reasons it is obligatory thatappropriate loss-of-mains (LOM) protection is applied in the DG unit interconnectionpoint to ensure that the DG unit is always disconnected when the connection to the mainsystem has been lost. [Brü 05] Intended islanding, which can have a tremendouslypositive effect on the reliability of the supply, is a completely different story and it willbe discussed later in the chapter 5.4.4.

Most of the LOM protection methods are based on detecting the changes in voltageand frequency, which usually take place when a network section is islanded. Thechanges in voltage and frequency are caused by the imbalance between active- andreactive power production and the respective consumption in the islanded networksection. Active power balance mainly determines the frequency of the power island,whereas, reactive power balance mainly determines the voltages of the islanded networksection. There is, however, a risk that the power imbalance in the power island is notsufficiently large to cause any detectable changes in voltage and frequency. This blindarea of LOM protection in the surroundings of the production- consumption equilibriumis called the non-detection-zone (NDZ). [Mäk 07b] Figure 2.7 shows what a non-detection-zone of a traditional over/under- voltage and -frequency protection might looklike.

16

Figure 2.7. Non-detection zone for traditional voltage and frequency protection[Mäk 07b]

The U > Umax marking in the figure refers to the overvoltage limit, whereas, theU < Umin marking refers to the undervoltage limit. Respectively, the markings f > fmax

and f < fmin refer to the over- and underfrequency limits. This kind of traditional voltageand frequency protection is probably the most utilized method due to its simplicity.There are, however, other more sophisticated LOM protection methods as well and theywill be discussed in chapter 5.

17

3. IMPACTS OF DISTRIBUTED GENERATION

The presence of DG can have many positive impacts on the distribution network usagewhich are listed in table 3.1. The realization of these positive impacts, which are oftencalled “system support benefits”, is, however, is not self-evident but depends on thereliability, location, size and controllability of DG resources. [Bar 00] Voltage support,for instance, is largely dependent on the type of the DG unit but also on the way that theDG units are required to be operated. The voltage control capabilities of directlycoupled wind turbines using induction generators are very poor, whereas, converterconnected DG units have relatively good abilities for supporting network voltagesprovided that the dimensioning of the converter allows this. [Ack 05] The larger the DGproduction in a feeder, the more important is the coordination of the DG operation andfeeder operation strategies. [Bar 00] In the EU, there is, however, no obligation for theDG unit owners to collaborate with the network utility. DG can sometimes also increasethe reliability of the supply by enabling the supply restoration on a larger area than whatwould be possible without DG. This, however, is questionable in case of DG units thathave low availability on demand (see table 2.2).

Table 3.1.Positive impacts of distributed generation on distribution networks [Bar 00]Positive impacts of DG on distribution networkVoltage support and improved power qualityLoss reductionImproved system reliabilityTransmission capacity releasePostponed network infrastructure upgrades

The presence of DG, however, also raises many new challenges. The most serious ofthese are probably related to network protection and voltage levels. In the traditionalelectric power system design the flow of electric power has been unidirectional, namelyfrom the transmission grid towards lower voltage levels as explained earlier.Unidirectional power flow has enabled relatively simple network design especially fromprotection perspective. The presence of distributed generation is, however, nowchanging this simple basis. [Jen 00, Mäk 07a] This chapter presents the most importantnew challenges that DG has brought up.

18

3.1. The impact of DG on voltage levels

Distribution network utilities have the obligation to maintain the network voltageswithin predefined levels. At present, this is mostly done controlling the tap changer(s)of the main transformer(s) and by building a strong network. In a network where there isno generation connected, the highest voltage can be found from the substation bus andthe lowest voltages from the end of the feeders. [Jen 00]

Traditionally, the voltage drop at the end of the feeders has been one of the principaldimensioning constraints in network planning. The deepest voltage drop on a feederoccurs during maximum demand situation when there is no generation connected to thisfeeder. Some new dimensioning factors, however, need to be included when DG ispresent. These new dimensioning factors from the voltage level point of view aremaximum DG production combined with minimum demand and minimum DGproduction combined with maximum demand. For a lightly loaded distribution networkthe approximate voltage rise due to DG can be obtained from equation (3.1), where Rand X are the resistance and reactance of the circuit, P and Q the active and reactivepower of the DG and V the nominal voltage of the circuit. [Jen 00]

VXQPRV (3.1)

Problems related to voltage levels are typically found from weak rural networks. Urbannetworks are usually stronger and shorter, and thus, rarely suffer from problems relatedto voltage levels. Increased fault levels may, however, sometimes become a problem inurban networks when DG is present. [Dti 05]

3.2. The impact of DG on network protection

When DG is connected to distribution networks there are multiple power sources andthe assumption of unidirectional power flow is no longer valid. [Rep 05b] This raisesnew challenges for distribution network protection. There are cases where the feederrelay becomes blinded during a fault because of the fault current contribution of DGunit located on the same feeder with the fault. This problem can often be overcome byutilizing more sensitive protection settings. The more sensitive the settings are,however, the more prone to nuisance tripping the DG unit is during faults on adjacentfeeders. When planning appropriate relay settings for the protection of a distributionnetwork including DG, the planning engineers have to bear in mind that the protectionwill have to work properly also when DG units are disconnected [Rep 05b]. In additionto these problems the DG also brings with the problems related to islanding detectionand failed reclosing problems. It is, thus obvious that special attention to protectioncoordination will have to be paid when connecting generation units to distributionnetworks in order to ensure safe operation. These protection challenges as well as the

19

effect of system earthing and generator types on fault detection are discussed in thischapter.

3.2.1. Protection blinding

The reach of an overcurrent relay is determined by the minimum fault current that willcause the relay to trip. This minimal current setting should be such that the reach of theovercurrent relay extends to the next recloser or covers the whole radial networkdownstream from the CB controlled by the overcurrent relay in case if no reclosers areused. [Dug 01] The presence of DG affects the reach of relays in certain situations. Asituation where the operation of a protective relay is delayed or even completelyhindered because of the fault current contribution of a DG unit is called protectionunder-reach or protection blinding. This might occur when a DG unit is feeding faultcurrent parallel with the supplying substation as presented in figure 3.1. This being thecase, the current seen by the relay protecting the feeder is reduced due to the faultcurrent contribution of the parallel feeding DG unit. [Mäk 05]

Protection blinding is especially problematic when definite time characteristics inovercurrent relays are applied. In this case the feeder protection might becomecompletely non-operational. In the case of overcurrent relays that are configured to useinverse time characteristics the feeder relay is not likely to be completely blinded butthere is still the danger of delayed operation which might cause the thermal limits oflines and components to be exceeded. The blinding problem can be mitigated by settingmore sensitive tripping values to the relays but this, on the other hand, might causenuisance tripping during faults on the adjacent feeder, in extreme production / demandconditions or because of the starting currents of DG or other rotating devices.Constraining the DG unit operation and network reinforcements can also be used tomitigate the relay blinding problem but these increase the costs of DG unit and maytherefore render the construction DG unit economically unfeasible. Changing theelectrical parameters of the DG unit can also be used to tackle the blinding problem butthis, of course, can only be done in the planning phase. [Mäk 05]

20

Figure 3.1. DG unit causing theblinding phenomenon [Mäk 05]

Figure 3.2. The idea of common feedpoint (CFP) [Mäk 05]

The theoretical background of the blinding phenomenon can be better understood withthe help of the common feed point (CFP) concept which is illustrated in figure 3.2. Thecommon feed point is the furthest point from the fault that is yet fed in parallel by thesupplying network and the DG unit. If there was no DG unit in the network the faultcurrent in the network model could be obtained from equation 3.2. The term Ufault standsfor the voltage in the fault point just before the fault, whereas, the impedance Znet

includes the impedance of the supplying network in addition to the impedance of theline between supply point and the common feed point. The impedance Zfault_b representsthe impedance from the CFP to the fault point including the fault impedance. [Mäk 05]

bFaultNet

FaultFault ZZ

UI_

(3.2)

Let us now consider that the DG unit is connected to the network as shown figure 3.2.The thevenin’s impedance Zth can now be obtained by equation 3.3.

NetGen

NetGenbFaultTh ZZ

ZZZZ _ (3.3)

With the help of this thevenin’s impedance we can now calculate the feeder current seenby the relay:

21

GenNet

netGenbFault

Fault

GenNet

Gen

Th

Fault

GenNet

GenFeeder

ZZZZ

Z

UZZ

ZZ

UZZ

ZI

_

(3.4)

Which can be further reduced as shown below

netGen

NetbFaultbFault

Fault

netGenGenNetbFault

FaultGenFeeder

ZZ

ZZZ

UZZZZZ

UZI

__

_ )( (3.5)

From equation (3.5) we can see that if the fault bus impedance Zfault_b equals to zero, thefeeder current respectively equals to the fault current in the case where no DG waspresent. This, however, could only happen in case if a fault with no fault impedancewould occur in the line connecting the supply and the DG unit. In reality there is alwayssome fault impedance which means that the DG unit always affects the relay sensitivity.If the DG is disconnected from the network, the impedance ZGen will be close to infinityand the feeder current seen by the relay will again be equal to the original feeder currentin the case where no DG was present. Let us still compare the original feeder current(equation 3.2) where no DG was present to the case where DG is present (equation 3.5).[Mäk 05]

netGen

NetbFaultbFault

Fault

NetbFault

Fault

ZZ

ZZZ

UZZ

U_

__

(3.6)

From equation 3.6 we can clearly see that the current fed by the supply is always less inthe latter case is when the DG unit is connected provided that the fault impedance isgreater than zero (which is always the case in reality). The extent to which DG unitinterferes with the relay sensitivity is determined by the middle term, in other words, theratio between the product of ZFault_b and ZNet and the denominator ZGen as seen from theequation (3.6). [Mäk 05]

3.2.2. Selectivity problems

Distributed generation can sometimes cause unnecessary tripping of the feeder where itis connected to. This kind of situation can happen in such a case where a DG unit isconnected to one feeder and a fault occurs in some of the adjacent feeders fed by thesame substation. This being the case, the DG unit feeds the fault on the other feederthrough the substation bus and thus, of course, also through the relay protecting thefeeder where the DG unit itself is connected. If the current fed by the DG to the fault islarge enough, the relay, provided that it is not equipped with the directional protection

22

feature, will consider that a fault has occurred within its protection zone and trips thefeeder, where the DG unit is connected to, needlessly off. This is phenomenon which iscalled protection selectivity problem or sympathetic tripping problem is illustrated inthe figure 3.3. Selectivity problems are likely to occur on situations where the generatoron the first feeder and the fault on the other feeder are both located close to thesubstation. [Mäk 04] Also the type of the generator strongly influences to the likelihoodof this problem. The fault current fed by induction generators usually decays quicklyenough not to cause selectivity problems, whereas, synchronous generators can sustain aprolonged fault current which is more likely to cause problems. [Mäk 06b]

Figure 3.3. Protection selectivity problem caused by DG [Mäk 06b]

Selectivity problems can often be avoided with proper relay settings. If the currentsettings of the problematic relays cannot be changed, which is often the case, theproblem can also be solved by utilizing appropriate operation times of the adjacentfeeder relays. This can be done by setting the relay protecting the feeder where the DGunit is connected to, to operate slower than the adjacent feeder relays. If the latteralternative is preferred, care has to be taken that the delayed relay operation will notcause any thermal limits of network components to be exceeded. In cases where propersettings for non-directional overcurrent relays cannot be found, selectivity problem canbe tackled by utilizing directional relay protection. The replacement of old relays withnew ones that have the directional fault current detection included, however, naturallycauses extra expenses. [Mäk 04]

3.2.3. Failed reclosing problems

Temporary faults, such as earth faults caused by lighting strikes on overhead lines, aregenerally cleared by automatic reclosing. Typically, in case if the first reclosing shouldfail, one or two more reclosings are made before the CB is ordered into permanent openposition for the repair time. Automatic reclosing, however, becomes a bit more

23

complicated in the presence of DG because the DG units in the area affected by thereclosing will have to be tripped off the grid first before attempting to clear the faultwith the help of reclosing. This is because the DG units that are not disconnected beforethe reclosing sustain the voltages in the area so that the fault arc is not distinguished. Itis, therefore, necessary that all DG units are equipped with LOM protection thatdisconnect the DG units immediately after the connection to the main grid has been lostas already discussed in chapter two. Special care has to be given to the coordinationbetween the LOM – and feeder protection since there has to be a sufficiently long deadtime for the extinguishment of the fault arc. The reconnection of the DG units into there-energized network also has to be carried out with care in order to avoid dangerousstresses to the DG unit. This kind of coordination between the feeder protection and theprotection of the DG units is quite challenging, especially in case if fast reclosing isapplied. [Ple 03]

The application of longer CB open times or more sensitive LOM protection settingsmay sometimes be necessary to ensure correct protection sequence, although in somecases, the presence of DG may render autoreclosure completely unusable. Verysensitive generator protection settings also have the disadvantage that they may causenuisance tripping of the DG unit. [Mäk 06b] A failed and a successful reclosingsequence are illustrated in figure 3.4.

Figure 3.4. Reclosing problems caused by DG [Mäk 06c]

The left figure illustrates a failed reclosing sequence, whereas, the right figure shows asuccessful one. In the left figure, a DG unit connected to the feeder where theautoreclosure is applied maintains the voltage during the CB open time causing thereclosing action to fail. In the right figure, on the other hand, the LOM protectiondisconnects the DG unit in time and the network is thus de-energized resulting in asuccessful reclosing.

Failed reclosing caused by a DG unit

0

5

10

15

20

25

0,5 1 1,5 2 2,5Time [s]

Volta

ge [k

V]

DG unitmaintains thevoltage in thenetwork

Reclosing,fault remains

Fault occurs at 1 s

First trippingis performed

after 0.35 s

Correct operation of DG unit protectionduring a reclosing sequence

0

5

10

15

20

25

0,5 1 1,5 2 2,5

Time [s]

Volta

ge [k

V]

DG unitdisconnected by itsprotection

Successfulreclosing

24

3.2.4. The influence of the DG unit type

The behavior of a DG unit during faults is strongly influenced by the DG unitimplementation and type of the generator applied. The generator types can roughly bedivided into three groups which are induction- and synchronous generators andinstallations applying static power electronic converters. A generator of some kind mayalso be connected to the last mentioned one but the converter dictates the behavior ofsuch an installation. [Mäk 06a]

Synchronous generators are widely applied in small scale hydro-, CHP-,reciprocating engine based power plants but also in some converter connected windpower installations. These generators are usually designed to be able to feed prolongedfault currents to the network during faults which, on the one hand, is harmful to thenetwork but, on the other hand, makes the fault easier to detect. [Mäk 06a] Figure 3.5illustrates the typical form of a fault current fed by a synchronous generator. As it canbe seen from the figure, the fault current usually decays to some extent after the initialpeak but the field forcing feature can raise the current a bit after a couple of seconds.

Figure 3.5. Typical form of a fault current fed by a synchronous generator [Mäk 06a]

Induction generators are applied in wind power installations and in micro-scale hydropower plants [Mäk 06a]. Unlike synchronous generators, induction generators are notcapable of supplying continuous fault current during three phase faults because thereactive power supply required to sustain the excitation of the induction generator isinterrupted in such faults [Jen 00]. Figure 3.6 illustrates the form of a fault current fedby an induction generator. The initial fault current fed by this generator type is roughlythe same compared to the one of a synchronous generator. However, the fault currentfed by induction generator decays strongly after the initial peak in symmetrical faults.[Mäk 06a]

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Figure 3.6. Typical form of a fault current fed by an induction generator [Mäk 06a]

Power electronic devices such as converters can be used to obtain better control andefficiency of a power plant. [Mäk 06a] The better efficiency stems from the fact that theDG unit is allowed to rotate at whichever speed that is optimal for it when convertersare used. Converters are also used for inverting the DC generated by some energysources like photovoltaic and fuel cells. [Jen 00] The power electronic interfaces dictatethe fault current characteristics even if traditional generators are used. Generallyimplementations using power electronics can only feed an initial peak current which isshortly after rapidly cut down. It is, however, possible to build devices capable offeeding prolonged fault currents as well. [Mäk 06a] The dimensioning of thesemiconductors used in the converters determines how large currents the converter canfeed. Overdimensioning of the semiconductors is, however, not the common practicebecause of their high cost [Mac 03].

3.2.5. The influence of DG on earth fault protection

The main purpose of system earthing is to protect network components, operationalstaff, general public and property in general. Generally four different types of earthingarrangements are used in electrical networks. These are direct earthing, earthing throughimpedance, earthing through suppression coil and isolated earth system. The way bywhich the system is earthed affects the behavior of the system in unsymmetrical faults.Generally one can say that the lower the earthing impedance, the higher the earth faultcurrents and the lower the overvoltage during earth faults. In directly earthed systemsthe earth fault currents can actually exceed the short circuit fault currents, whereas, insystems with isolated earth the earth fault currents are often even smaller than the loadcurrents. [Lak 95]

The suitability of various types of earth fault protection is dependent on the type ofthe earthing applied in the network and the required sensitivity and selectivity ofprotection. Conventional earth fault detection methods cannot be applied in network

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with isolated earth or in networks that are earthed through arc-suppression coils becausethe earth fault currents in such networks are very small. Earth faults in such networks,however, cause asymmetry in both voltages and currents and not just on the feederwhere an earth fault has occurred but on the whole distribution network fed by the samemain transformer. These asymmetries can be applied for the detection of earth faults.The zero voltage is measured at the substation bus and the currents at the feeder relaymeasurement points. Since the whole network is affected by the fault the feeder relayswill, nevertheless, have to be equipped with the directional earth fault feature in order todiscriminate on which feeder the fault has occurred. [Lak 95]

At present, the common practice is to leave the earth fault protection of DG units to beundertaken by the LOM protection. This means that the DG unit will only bedisconnected after the formation of an island caused by the opening of the feeder relay.This arrangement can sometimes be problematic because of the NDZ of the LOMprotection. [Mäk 07c] Long term islanding is a rare event because it is only possiblewhen both active and reactive power production and consumption are in equilibrium.Momentary islanding lasting few hundred milliseconds, on the contrary, is a commonphenomenon. [Kum 05] The fact that LOM protection will probably not operateinstantly after the operation of the feeder relay but with a certain delay is problematic inthe sense that the DG unit in the islanded zone can sustain the earth fault which resultsin dangerous step and touch voltages. Faster disconnection of DG unit is thus desirable.In the case of earth faults, this could be achieved by adding earth fault protection to theDG unit interconnection point. [Mäk 07c] This, however, is often problematic becauseDG units are commonly connected to the network through delta-wye type blocktransformers which create a point of discontinuity to the zero sequence network.Because of this point of discontinuity the zero sequence network values at the LV sideof the transformer cannot be utilized for detecting earth faults in MV network. [Kum05] The point of discontinuity in the zero sequence network also means that thepresence of DG does not interfere with the operation of feeder protection in earth faultswhich, on the contrary, is the case with short circuit faults. [Mäk 07c]. The MV sidevalues of the block transformer, however, could, in some cases, be utilized for detectingearth faults. The use of the MV side values for the earth fault protection of a DG unit isa promising solution if the DG unit is situated close to the block transformer. This ideamight, nevertheless, not be quite so promising if the DG unit is located further in the LVnetworks because this would necessitate costly communication between the DG unitand the transformer station. [Kum 05]

3.3. Other impacts of DG

DG has also many other effects in addition to the ones that have so far bee discussed inthis thesis. These other effects are, however, only briefly presented here because of thelarge scope of the topic. Some of these other effects are listed in table 3.2. The impacts

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of DG on fault levels as well as the economical impacts of DG are, nevertheless, alsohighlighted issues and they are, therefore, shortly discussed in chapters 3.3.1 and 3.3.2.A more extensive survey concerning the other impacts of DG can, for example, befound from the references [Jen 00] and [Rep 05b].

Table 3.2.Other issues needing attention because of DGCommunication requirements System frequency- and stability issuesNew contractual requirements Power qualityIncreased complexity for network planning Increased operational complexityEconomical impacts Fault levels

3.3.1. Impact of DG on fault levels

Fault level is a good indicator for network robustness. High fault level signals from thenearness of a highly interconnected power system or of a generating station. The goodthing about high fault levels is that on a feeder with high fault level, voltage profiles arevery good (voltage drops are small) and rapid and reliable protection is easilyestablished. There is, however, also a downside in high fault levels, namely the fact thatthe network components have to be dimensioned to withstand the high fault currents,which can be costly. A compromise between the robustness and dimensioning (costs) isthus desirable. [Wu 03]

Both synchronous and asynchronous generator based DG contribute to faultcurrents. In some areas where the fault levels are already close to the switchgear currentratings, the connection of a DG unit may cause these ratings to be exceeded. Thecomponents whose ratings are exceeded can, of course, be changed to components withhigher ratings but this is usually costly. The component upgrade costs are oftenallocated to the DG unit owner which may render the whole DG project uneconomical.[Jen 00]

Fault level contribution of a DG unit is dependent on a number of factors. The typeof the generator and the way the generator is connected, for example, affect the formand the magnitude of the fault current as already discussed earlier. Converter connectedgenerators feed much smaller fault currents compared to directly connected generators.The impedance between the generator and the fault point which is dependent, forinstance, on the distance and configuration between the fault point and the generator,also affects the fault current magnitude fed by the generator. [Dti 05]

3.3.2. Economical impacts

The addition of DG usually decreases the power exchange (most often the import fromthe grid) between distribution networks and the transmission grid. The case can,however, be the opposite in some rare cases if the aggregate DG production notablyexceeds the consumption in the distribution network fed by the same main

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transformer(s). The reduction of the imported power from transmission network is aclear financial benefit for the distribution network companies because the grid fees theyhave to pay are thus reduced. [Rep 05b] This can be clearly seen from table 3.3 wherethe grid fees of the main Finnish transmission network operator are listed.

Table 3.3.The grid fees of the main transmission system operator in Finland [Fin 09a]2008 2009 2010 2011

Consumption feeWinter period 2.16 2.28 2.4 2.52 € / MwhOther times 1.08 1.14 1.2 1.26 € / MwhUse of grid feeIntake from grid 0.66 0.68 0.7 0.72 € / MwhInput into grid 0.3 0.3 0.3 0.3 € / Mwh

Connection point fee 1000 1000 1000 1000€ / connection point/Month

All prices excluding tax

The change of the losses in distribution networks due to DG is dependent on factorssuch as the location of a DG unit in relation to the loads, the thickness of conductorused, the production in relation to consumption and the timely correlation betweenproduction and consumption. The distribution losses will decrease if a DG unit isconnected to a feeder where the consumption exceeds the production of the DG unit.The distribution losses, on the other hand, will increase if a DG unit is located on aradial feeder dedicated to production only because in this case the power fed by thegenerator will first have to flow to substation and only then to the loaded feeders. A DGunit connected to substation bus only affects the losses occurring in the maintransformer in the MV network side. The losses in the HV network are usuallydecreased due to DG. [Rep 05b]

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4. ACTIVE DISTRIBUTION NETWORK

Distributed generation can enhance the utilization of distribution networks. DG,nevertheless, also complicates the management of distribution networks and can bringvarious problems to distribution networks if networks are operated passively as today.Extra generation capacity in a network that is operated passively is created by replacingexisting primary network components like conductors and transformers with ones thathave higher ratings. This approach is very costly and can render DG economicallyunfeasible. There is, therefore, a lot of discussion concerning the characteristics of thekind future distribution system that is able to cope with the new needs and challenges.Words like active distribution network, smart grid, intelligrid and power cell are oftenused when discussing of these kinds of future power systems. The basic idea of theseconcepts is to make use of the full potential of DG and other existing networkinfrastructure by utilizing the entity in an intelligent manner.

Active distribution network, which could be described by adjectives such asintelligent, flexible, integration and co-operation [Tut 08a], is a concept of a new type ofdistribution network that is able to facilitate connecting DG to the network, improvingpower quality and increasing the utilization rate of the network. These network featuresare achieved by controlling the active resources (DG units, controllable loads, FACTSdevices, energy storages, the HV/MV transformer tap changers and plug-in electro-hybrid vehicles) according to ANM. The secondary systems like the IEDs, theautomatic meter reading (AMR) system and the well established IT tools form thebackbone of ANM by providing the required intelligence to active networks. The real-time information provided by the AMR devices and IEDs can be used both for theoperational as well as for long term planning purposes. Effective and reliablecommunication is essential for the successful use of active network management. Thevarious fields of study concerning active distribution are depicted in figure 4.1. It isimportant to take into account all these fields and their interrelations. The futurenetwork infrastructure, for instance, needs to enable the development of customer levelenergy market features like demand response and customer-oriented-services (real timepricing, elastic load control) but it also needs to cope with the energy market trends likewith the increasing amount of DG. The new distribution network environment, on theother hand, creates new business opportunities and thus influences the energy market.The studying of various active network architectures is also essential for creating themost suitable future network infrastructure that also supports the needs of energymarket. [Jär 09]

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Figure 4.1. The concept of active network

DG units have traditionally been connected to distribution networks with the so calledfit and forget principle thus considering the connected DG unit merely as a negativeload. This kind of thinking will often necessitate remarkable network reinforcementneeds which may ruin the competitiveness of DG. These costly primary networkequipment investments can usually be replaced by much less costly investments oncontrollability, information systems and telecommunication when DG units areconnected to the distribution network with the ANM way of thinking. The utilization ofANM, however, requires that the DG units are integrated to the active network both bypaying attention to the system requirements and with the help of ancillary services. [Tut08a] The main driver for ANM is the strongly increasing amount of DG but also theregulatory pressure demanding more reliable and efficient network with the least costhas its role [Eat 06].

4.1. Distribution network planning

Distribution network design is traditionally based on the so called worst case planningprinciple. In radial distribution networks, where no DG is present, the limiting worstcase factors are derived from the voltage drop along the feeder and the thermal limits ofthe conductors. The lowest voltage is found at the end of the feeder during maximumload. [Lak 95] When DG is present in the network, the worst case will occur in acombination of minimum DG production together with maximum load. In lightlyloaded networks, the presence of DG will, however, introduce also another limitingworst case factor. This is the combination of maximum DG production together withminimum load, which might cause the maximum allowable voltage to be exceeded atthe DG interconnection point of the feeder line. [Jen 00]

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The worst case design principle has been considered satisfactory in networks whereonly few relatively large DG units are interconnected. The validity of this principle is,however, no longer quite so justified when a large amount of DG units based on variouskinds of energy sources are connected to the distribution network. This is because it isquite unlikely that all the units would be operating at their maximum output limits at thesame time. There are also some DG units like CHP plants whose power output is notcompletely independent of the demand. The electric power output of CHP correlateswith the demand to some extent because the way they are run is governed by the heatdemand. The worst case principle is, therefore, a fairly conservative design principle fornetworks with a high DG penetration level. [Rep 05b] Voltage level problems arecommon in weak rural networks but rare in strong urban networks where fault levels area bigger concern. One should also pay attention to quick voltage changes and flicker inthe planning phase.

4.1.1. New planning principles for distribution networks including DG

Statistical planning offers a more fair way for assessing the allowable DG penetrationlevel. In this type of planning, the load curves used in the network information system(NIS) are extended with DG production curves, which are based on long-term statisticsof temperature and wind speed. The production curves are based on long-term statisticsbecause of the stochastic nature of temperature and wind. By performing a load flowcalculation from the data obtained from the two combined curves, it is possible tosimulate the hourly functioning of the network. Statistical network planning is,however, not limited to certain fictive hourly conditions but a series of different curvesare used for studying the possible network conditions. The load-flow calculations can beused to find out the limiting network constraints and their duration. They can also beutilized for DG interconnection studies, and furthermore, for the comparison betweennetwork reinforcement and active network management strategies. The hourly load flowinformation can also be helpful in estimating the DG interconnection charges, whereas,for network operational purposes special estimates should be used instead of productioncurves as they, unlike the load curves, are not accurate. [Rep 05a]

The amount of allowable DG can be evaluated according to the traditional worstcase principle based firm capacity or, alternatively, according to the statistical planningbased non-firm capacity. The purpose of the non-firm interconnection is to allow ahigher DG penetration compared to the firm-capacity by increasing the distributionnetwork transfer capability. The increased transfer capacity is achieved by using thenetwork more precisely. This is done by utilizing the DG units, for instance, for voltagecontrol when the network constraints occur occasionally. Ancillary service contractsbetween the DG unit owners and the local DNO are, of course, required to provide thecontrollability of the DG units for the DNO. [Rep 05a]

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Situations where the active power output of non-firm capacity units have to beconstrained may arise because of the stochastic behaviour of non-firm capacity. Non-firm connections are, therefore, most suitable for DG units that have a fairly lowutilization time of maximum production. Non-firm concept is also suitable in case if thetransfer capability of the network is exceeded only occasionally or in case if the networkreinforcements required because of the DG unit interconnection would render the DGunit uneconomical. The utilization of non-firm connection concept is, nevertheless,meaningful only if both the DG unit owner and the network company in questionbenefit from the arrangement. [Rep 05b]

4.1.2. New requirements for computerized network planning

Because of the lack of suitable NIS for DG related studies, protection planning studiesin networks including DG is commonly carried out by using dynamic simulationsoftware. Such software provides accurate results if the simulations are prepared withcare. The planning procedure should, however, at least from the DNO’s point of view,be efficient and yet accurate enough as the DG interconnection studies are becoming aroutine operation. In order to accomplish this, new efficient calculation methods shouldbe included to the present planning tools. [Mäk 06a, Mäk 06b] Such calculationmethods and their applicability to NIS presently used are discussed in [Mäk 06a], [Mäk06b], [Mäk 07d] and [Mäk 08].

As already discussed in chapter two, the present NIS’s are usually based on steady-state calculations and rms values. This has been sufficient so far, but the need for thesystem to be able to take DG into account is raising new requirements. In the faultanalysis of the present NIS’s, DG can be taken into account as a constant short circuitsource. This is sufficient for large synchronous generators but not for other types ofgenerators or converter connected units which are being widely applied today. Thisdeficiency of present NIS software could be fixed by “stretching” the steady-statecalculations. The “Stretching” means that the short circuit calculations are looped insuch a fashion that the effect of DG can be taken into account. This looping is possiblebecause the short circuit calculations do not require substantial calculation power.During each loop the fault current fed by a DG unit is altered while the other componentvalues are left untouched as steady state values. [Mäk 07d]

There can still be some complicated simulation cases where more advancedsimulation tools are needed. For such studies, it would be beneficial to develop astandard interface between NIS and the more advanced simulation program utilized inorder to minimize manual data transfer. It must, however, be noted that the modeling ofnetwork components in present NISs is considerably more simplified compared toadvanced simulation tools. Present NISs also lack the data required for dynamicsimulation studies. This means that there would still be manual work to be done whentransferring the network model from NIS to the other program.

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4.1.3. General protection planning procedure

General protection planning procedure aims to carry out all the protection setting studiesrequired for a new DG unit installation. The idea in the procedure is to study all theneeded changes to the protection of feeders and the requirements for the DG unitprotection. The output power and the location of the DG unit are given as an input bythe user while other required information is acquired from the NIS database. It isevident that changes made to one relay may lead to a need to change the settings ofother relays as well. General protection procedure is, therefore, iterative by its nature. Ifchanges to one relay are made, the functioning of other relays has to be checked as welluntil it is verified that all protective devices function correctly. The protection settingplanning practically requires that fault calculations are performed point by point on thestudied feeders. [Mäk 07d]

Because of the above explained repetitive nature of general protection procedure, itwould be relatively simple to automate the procedure and implement it in a modernNIS. A NIS with this procedure included could perform the protection setting studieswithout the need of any user interception but the final decision making still has to be leftfor the user due to the critical nature of these decisions. The extension to the steady statecalculation of NIS presented in the previous subchapter could be used to enhance theaccuracy of general protection procedure. [Mäk 07d]

It would also be advantageous to implement general protection planning procedureto SCADA / DMS systems. With this function included, the control center engineerscould check the effect of network topology changes to protection beforehand. Thisfeature could prove to be very beneficial since a DG unit that is not disturbing theprotection under normal operating conditions can have detrimental effects when thenetwork topology is changed, for instance, during back-up supply arrangements. [Mäk07d]

4.2. Connection requirements

Small generation units have typically been considered to have merely a marginal effecton the power system and system operators have, therefore, allowed them to disconnectimmediately after any disturbances. Sensitive LOM protection settings are preferablefor DNOs because they prevent DG units from maintaining fault arcs thus enablingsimple and safe removal of temporary faults by auto-reclosing. Out of phase reclosingscan cause dangerous stresses to DG units, which makes fast disconnection of DG unitspreferable also for the unit owners. The amount of DG has, however, already reachedsignificant levels in some regions and consequently the TSOs have realized that toosensitive protection settings of DG units can have detrimental effects on the systemstability. This stems from the fact that faults in the transmission network can launchhuge amounts of adverse tripping of DG which has already been witnessed at least in

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18.2.1996 during a fault on a 150 kV line in the network of Danish ELTRA [Ple 03] andrespectively in 4.11.2006 in the UCTE system [UCT 07]. In the Danish case almost350 MW of DG based generation was tripped, whereas, the UCTE disturbance causedthe tripping of over 10 GW of DG based generation. [Ple 03, Tut 08a]

Many system operators have recently issued grid codes for DG that define how longthe generating units have to be able to stay connected and support the system stabilityduring various kinds of disturbances. These are also known as the fault ride through(FRT) requirements. [Mul 05] Figure 4.2 represents fault ride through requirements forwind turbines in the networks of various TSOs. The vertical axis shows the voltage dipexperienced by the wind turbine, whereas, the horizontal axis represents the voltage dipduration. FRT requirements are mainly meant for HV connected wind farms, but it islikely that similar kinds of requirements will be issued for MV connected units in thefuture as well especially in areas of high DG penetration level. DG units should alsowithstand greater variations in the system frequency. This would benefit the systemstability and facilitate the utilization of intended islanding for improving the quality ofsupply. [Tut 08a]

Figure 4.2. Fault ride through requirements of various TSOs for wind turbines [Tut08a]

FRT capability means that a generation unit is capable of enduring deep voltage dipsand feeding reactive power to the system thus supporting the network voltage. It is,however, not enough that the generation unit has FRT capability, but also the loss-of-mains (LOM) protection relay of the unit must be set to enable the FRT operation. Thismeans that the sensitivity of the LOM protection must be loosen which, in some cases,may pose a safety risk. [Tut 08a] The realisation of the FRT capability thus increases

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the risk of unintended islanding not only because of the necessity of loosening the LOMprotection settings but also because a DG unit that has FRT capability is more capableof maintaining power islands. In this sense, LOM protection settings are a compromiseof some kind between enabling FRT and avoiding unintended islanding. Figure 4.3illustrates how fulfilling the FRT requirements extends the size of the NDZ.

Figure 4.3. Loose protection settings increase the size of the Non-detection zone

There are no universally agreed recommendations for LOM protection settings of DGunits at present. The recommendations vary from country to country [Tho 09] and thereis also some controversy between the recommendations of the TSOs and manufacturers[Ple 03]. Table 4.1 shows over- and under voltage as well as over- and under frequencyprotection setting standards and recommendations. If the measured frequency or voltagevalues at a DG unit connection point should exceed the setting values, the DG unit isdisconnected instantly or after a defined delay as shown in the table. It can be seen thatmany of these protection requirements radically differ from the FRT requirements forgrid connected wind turbines that were presented in table 4.1. Some harmonizationbetween the LOM protection and FRT requirements will thus be needed if DG units arerequired to have similar FRT capabilities in the future. The table also shows that theprotection requirements concerning overvoltages are much stricter than respectiverequirements on undervoltages. This derives from the fact that undervoltages are usuallynot hazardous to customer equipment although they may cause malfunctions, whereas,overvoltages are hazardous to most of customer equipment and cannot thus be allowed.

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Table 4.1. Protection setting requirements and standards for DG units [Tho 09]Voltage Frequency

IEEE1547 V < 0.5 p.u., 0.16 s 30 kW

0.5 p.u. V < 0.88 p.u., 2 s f > 60.5 Hz or f < 59.3 Hz, 0.16 s1.1 p.u. < V < 1.2., 1 s > 30 kW1.2 p.u. V, 0.16 s f > 60.5 Hz, 0.16 s

f < 59.8 Hz - 57 Hz,adjustable 0.16 - 300 sf < 57Hz, 0.16 s

Belgium LV: V > 1.06 p.u. instantly, f < 49.5 Hz or f > 50.5 Hz, instantlyV < 0.5- 0.85 p.u., delay 1.5 sMV: 0.25 - 0.5 p.u. > V orV > 1.1 p.u. instantly,V < 0.5 - 0.85 p.u., delay 1.5 s

France V < 0.85 p.u. or V > 1.15 p.u. instantly f < 47.5 Hz or f > 51 Hz, instantlyItaly V < 0.8 p.u., 0.2 s V > 1.2 p.u., 0.1 s f < 49 - 49.7 Hz or f > 50.3 - 51 Hz

instantly, 0.5 Hz/s instantlySpain 0.85 - 1.1 p.u., delay 0.5 s 49 – 51 Hz, delay 0.1 s

Germany V < 0.8 p.u. or V > 1.15 p.u., 0.2 s f < 49.8 Hz or f > 50.2Hz, 0.2 s

The contradiction between sensitive protection settings and FRT capability could besolved by developing more sophisticated LOM protection schemes that would removethe necessity to immediately disconnect DG units during abnormal voltage or frequencyconditions. [Tut 08a] The communication between feeder and LOM protection IEDs,which will be discussed more in detail later, could be an adequate solution for thisproblem.

4.3. Ancillary services

Ancillary services are extra services performed by a customer owned resource like a DGunit that the local network company or to the system operator can purchase. Ancillaryservices are vital for active network management because they are the medium bywhich the controllability of various active resources is brought to the DNO. Voltagecontrol, frequency control, island operation, power flow management and supplyrestoration are examples of possible ancillary services that will be discussed in the nextchapter. [Rep 05b] Ancillary services can be brought to the DNO either by a marketbased approach or grid code based approach. In the market based approach ancillaryservices are bought from an ancillary service market or alternatively direct contractsbetween the resource owner and the DNO are made, whereas, in the grid code approachthe network users share the responsibilities needed for the system operation. [Tut 08a]DG provided ancillary services need to be economically attractive not only to theowners of DG but also to the DNO as well [Ile 04].

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The ANM could bring financial benefits for all parties involved in the distributionnetwork level. Network companies could obtain financial benefit from the ANM byselling it as a service to DG unit owners, who, in turn, could receive increased profits inform of increased electricity sales. [Ack 05] Improved supply quality, which the ANMcould also enable, would also be a clear financial benefit for the network companies.[Rep 05b] This is because supply quality (mainly reliability) is directly linked to theallowed profit of network companies in many European countries. [Vil 04] Networkcompanies could additionally make use of the improved power quality achieved withthe help of ancillary services by offering connections with extra high power quality todemanding customers. [Rep 05b] The ANM could also benefit the consumers bylowering the network fees because of the maximized utilization of the network assets.[Ack 05]

The service contracts should define specifically how the network company can usethe DG unit and how the control is established. If the price of the ancillary contractswould be fair enough, there could even be third party owned DG units solely forancillary service purposes. Ancillary service contracts could, of course, also be made forother resources in addition to DG units like customer owned STATCOM’s orcontrollable loads. [Rep 05b] In many European countries DG units rated some tens ofMWs are required to provide frequency response and frequency reserve services,whereas, DG units rated below ten MW are seldom required to provide any services.Grid code obligations demanding frequency response capabilities from DG units arebeing increasingly made especially in countries like Germany, Ireland and Denmark,where the share of intermittent DG production has reached considerable levels. [Ile 04]

If DG should provide ancillary services both to the TSO and DNO, there can becases where a DG unit receives conflicting instructions from the two. These kinds ofpriority arrangements should always be taken into account in the ancillary servicecontracts. For TSO oriented services, passive network management is actually moresuitable than active network management. This stems from the fact that DG units shouldalways be able to respond to the service request of TSOs when the network is managedaccording to the passive strategy. When the network is actively managed, however, DGunits might not be able to respond the service requests of TSOs because of the possiblenetwork constraints. ANM is more suitable for the ancillary services meant for DNOsbecause DNOs are likely to demand more ancillary services from DG units when thenetwork is managed actively. [Ile 04]

4.3.1. Virtual power plant in the management of ancillary services

Virtual power plant (VPP) is a management system used for optimizing the use ofmultiple production units, controllable loads and energy storages. VPP could be apotential alternative for the management of ancillary services provided by DG. Specialcare would, nevertheless, have to be paid for the reliability of the VPP because of thecritical nature of the management task. One of the most potential ancillary services for

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DG units managed by VPP are primary frequency control, secondary frequency controland disturbance reserve services. The VPP can choose the economically optimalproduction mix for providing the requested services. [Rau 08]

The control of distributed energy resources for frequency control purposes can bebased on local frequency measurements or outer control signals. System frequency ismore suitable for primary frequency control and frequency response services because ofthe demanding requirements on speed and reliability of providing the service.Secondary frequency control services are, however, managed manually which makesthe use of local frequency measurements as control signal inadequate. Reliablecommunication channels between the distributed energy resources and the VPP are,thus, necessary for VPP managed secondary frequency control services. Therequirements on speed of these communication links are, however, not very highbecause of the manual control of this service. [Rau 08] Figure 4.4 illustrates the idea ofVPP concept. VPP can control a large variety of DG units and loads and sell theaggregated capacity as a specified ancillary service to the TSO. The multiple DG unitsand loads in the distribution network controlled by the VPP are now reduced to a singleservice provider with specific performance characteristics from the TSO point of view.

Figure 4.4. The idea of virtual power plant [Rau 08]

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VPP could also be used for the management other ancillary services like voltagecontrol, power system oscillation damping for the improvement of steady state stability,power flow management, island operation and black start [Rau 08]. The suitability ofVPP to the provision of some of the above mentioned ancillary services is discussedmore in chapter 5

4.4. Communication arrangements

Security and availability of communication are of critical importance to networkcompanies and their role will probably keep growing if distribution networks are to bemanaged actively. This is because of the increased demands on awareness of thenetwork state and due to the need of establishing better communication links betweenthe various active resources and control center. Because of the importance ofcommunication arrangements to DNOs, network utilities often have their owncommunication networks [Ber 07]. As the complicity of the network grows along withthe movement towards active distribution networks, it will be very difficult andexpensive to manage data exchange between various devices and systems if all thevendors have their own protocols and interfaces. There is, therefore, a strong need forstandard protocols and vendor open interfaces (IEC-61850 for instance).

The physical communication mediums can be roughly divided into directly wiredand wireless systems. The first type mediums include for example copper wires, opticalwires and power line carrier, whereas the second types include for instance radiolink,radiophone and GSM. A more accurate presentation of various communicationmediums can be found from appendix 2. The most suitable type of communicationmedium depends on the needs for data transfer capacity, on the availability of existingcommunication mediums (for example availability of hirable public networks) and onthe transfer distances. [Ver 06] The extent to which intelligence is distributed alsoaffects the requirements on communication mediums. If, for instance, the localcontrollers of DG units only send information when certain predefined limits areexceeded or when disturbances occur, then the amount of transferred data will quitelimited. On the other hand, if all the DG units are sending real time data of concerningtheir operating point, the amount of transferred data will be very large.

A DNO is in big trouble if the communication arrangements are suddenly out ofservice due to an interruption in their power supply. It is therefore absolutely vital thatsufficient backup power supply to the communication infrastructure is arranged. Ifuninterruptible power supply (UPS) devices are used for securing the energy needs ofcommunication links, then consideration has to be given to the dimensioning of the UPSdevices, in other words, to the time that the UPS device is wanted to be able to providesufficient back up supply.

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Interruptions in the power supply of the communication links are, however, not theonly cause for the communication disruptions. For instance, interruptions in the AMRsystem have occurred due to problems related to capacity and poor signal strength ofcommunication networks hired from a service provider. A higher degree of reliability ofthe communication network can, of course, always be bought or built with a higherbudget. The DNOs will just have to assess, on the one hand, how much value they giveto reliability of communication and, on the hand, how much they are willing to pay forit. Since interruptions in the communication system probably cannot completely beavoided, active distribution networks should be designed in such a way that they are notcompletely paralyzed when problems with the communication system occur. This couldprobably be achieved by distributing a certain amount of local intelligence around thenetwork. Special attention should also be given to the functioning of the communicationsystem during large power network disturbances. This is because not only thecommunication links but also the network management systems can get jammed if allthe intelligent resources distributed around the network try to send alarms to the controlcenter simultaneously. The best way to avoid problems like this would probably be tocarefully design what kind of information the distributed intelligent devices are allowedto send upstream to the control center systems. SCADA could also be designed to filterand categorize the most important information from the vast amount of notifications. Itcould also be wise to enlarge the capacity of communication links to such an extent thatthe links were not overloaded during large network disturbances.

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5. ACTIVE NETWORK MANAGEMENT

The main purpose of active network management (ANM) method is to facilitate theconnection and operation of DG to distribution networks. This is done by utilizing theexisting network components in a more intelligent fashion instead of the traditionalpassive strategy. The utilization of ANM method does not require massive networkinvestments on new primary components but some upgrades are needed for controlcenter management systems like SCADA and DMS. Sufficient measurements andcommunication channels are also necessary for the use of centralized activemanagement strategies like coordinated voltage control. More efficient planning toolswould also be of great help to DNO’s as the present NIS software is not capable oftaking DG into account.

The transition from passive to active network management could improve thesupply quality. Voltage drop problems which are common in rural areas can, forinstance, often be solved by utilizing DG units or voltage regulators like reactive powercompensators, in-line transformers, SVCs and STATCOMs. In extreme conditionswhen these measures do not bring sufficient aid, load shedding can be harnessed tobring the voltage back to nominal value. Other power quality problems such as flickerand harmonics can also be tackled with the help of STATCOM and SVC devices. Islandoperation, in turn, can be used to enhance the reliability of the supply at times of longeroutages in the supplying network. Fault levels which were mentioned as one of theproblems related to DG can also be managed by various methods such as by networksplitting and by using fault current limiters. Protection problems are often mentioned asthe most restricting issue for the wider use of DG. Some solutions for the discussedprotection problems have, however, been developed and such are discussed in thischapter. Figure 5.1 shows an overview of an active distribution network.

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Figure 5.1. Overview of an active distribution network [Tut 08a]

As the figure illustrates, there can be a large set of various active resources workingtogether in an active distribution network, like DG units and STATCOMs. These activeresources can be locally controlled based on local measurements and intelligence oralternatively centrally controlled with the help of suitable control center software(SCADA, DMS), measurements (Automatic Meter Reading (AMR) devices, IEDs) andcommunication channels. These different active management concepts and tools will bediscussed in the following chapters.

5.1. Control hierarchy of distribution system

The existing control hierarchy of distribution system consists of four levels. Protectionsystem, which is the fastest of these levels, is designed to guarantee the safety ofnetwork operation in all situations. Protection system operates automatically without theneed of any interference of the user. The second hierarchy level, namely the automaticcontrol system, functions automatically based on local measurements and intelligence.This level includes features such as frequency control, local voltage control, loadshedding and production curtailment. Area control level, which is the third of thehierarchy levels, is based on centralized control. It includes features such as coordinatedvoltage control, power flow management, automatic network restoration and islandoperation. Network reconfiguration, which is the fourth and the last of the hierarchy

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levels, can be used for optimizing the operation of the distribution network by changingthe network configuration with the help of switches located all around the network. [Tut08a] In the following, the ANM method will be examined from the control hierarchypoint of view.

5.2. Protection system

The protection system is the first of the distribution network control hierarchy levels.[Rep 08] Its task is to make sure that power system is operating within its normal limits.If a system hazard, say a short circuit, should occur, the protection system must reliablyremove the faulted part from the rest of the network and restore the best possibleconditions that are available. The protective actions have to be undertaken automaticallyand rapidly enough in order to avoid further damage. [And 99]

The increasing amount of DG is raising new challenges for the distribution networkprotection system. Protection misoperations can lead to dangerous situations and cannot,therefore, be tolerated. [Mäk 06a] In order to overcome these challenges, new ways ofnetwork protection need to be considered. Distance and differential protection schemesare now being considered as possible solutions to challenges raised by DG indistribution networks. [Rep 08] Directional overcurrent scheme and sectionalizing CBscould also be used as a means to counter the new protection challenges. [Kum 06a]. Thecoordinated planning method for studying the operation sequences of the protectiveIEDs in networks including DG that was already discussed in chapter four could also beof great help in developing a new protection system capable of managing the challengesraised by DG.

5.2.1. Sectionalizing circuit breakers

Sectionalizing circuit breakers are CBs that are placed along the feeders for improvingthe supply reliability. The use of this kind of CBs is particularly beneficial in feederswhere a great proportion of the customers are situated in the first part of the feeder and agreat deal of the faults occurs in the second part of the feeder. In feeders like this, asectionalizing CB can be placed at the end of the first section of the feeder thus reducingthe number of interruptions experienced by the customers located at the first section ofthe feeder. This idea is illustrated in figure 5.2.

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Figure 5.2. A network where a sectionalizing circuit breaker is used

The interruptions in the first part are reduced because a fault occurring at the secondpart of the feeder no longer causes an interruption in the first part since thesectionalizing CB disconnects the second part from the healthy first section during suchoccasions. The number of interruptions in the second part is, nevertheless, not reducedat all unless it is being fed from the other direction (ring network). The coordinationbetween the first feeder relay at the substation and the sectionalizing CB requiresattention in order to achieve selective protection without slowing the operation times ofthe original feeder relay too much. [Sal 06] More than one sectionalizing CBs cannaturally also be used but the first one brings the greatest benefit [Kum 06a].

5.2.2. Directional overcurrent protection scheme

Directional overcurrent protection scheme functions as a normal overcurrent relayexcept that it is also able to detect the direction of the fault current. In other words,directional overcurrent relays trip only if the current magnitude exceeds the trip marginand, additionally, the direction of the fault current equals to the setting direction. [Kum06b] The operation time of this protection scheme can either be based on constant orinverse time tripping. The tripping time is proportional to the current magnitude wheninverse time mode is used. [ABB 00] Because of the ability to determine the direction ofthe fault, directional overcurrent protection could be used for tackling the selectivityproblems caused by DG. [Kum 06b] Directional overcurrent protection does,nevertheless, not solve the problem related to protection blinding which was discussedin chapter 3.

The detection of the fault current direction can be based on many methods. Onetraditionally used method is based on comparing the fault current of each phaseseparately to the opposite principal voltage. For example, the current of the first phase(I1) is compared with the principal voltage phasor U23. The relay launches a trip signal ifany of the phase currents exceeds the trip margin and is toward the forward direction (orto the opposite direction depending on the settings). It is, of course, necessary for thissort of operation logic that the relay stores the voltage phasors in its memory so that

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they are available also during three phase faults. Other methods also for determining thecurrent direction exist and such are presented in [ABB 00]. [ABB 00]

5.2.3. Distance protection scheme

Distance protection scheme is capable of determining the distance between themeasurement point and the fault point. The use of this protection scheme often enablesmore rapid operation times and easier coordination compared to directional overcurrentprotection schemes in meshed networks. The determination of the distance is based oncalculating the impedance between the fault point and the measurement point of theIED. The impedance is calculated by dividing the current phasor by the voltage phasorwhich, of course, necessitates both current and voltage measurements. The actualdistance is then achieved by comparing the impedance calculated from themeasurements to the known impedance (known provided that the line length andelectrical parameters are known) of the protected line. [And 99] The utilization ofdistance protection can be very beneficial in meshed networks or in radial networkswith sectionalizing CBs. This protection scheme is, however, not the most suitable forsimple radial distribution feeders that are only protected from the beginning of thefeeder, in other words, feeders that do not have any sectionalizing CBs.

The idea of this protection scheme is to create protection zones (generally from 2-3in distribution networks [Fri 01]) which have their respective operation times. The firstzone is usually set to cover only some 80 to 90 % of the protected line in order to makesure the IED will not trip on faults that occur behind the next CB. The protection onzone one can then be set to trip instantaneously. [And 99] The second zone, on the otherhand, will be set to extend behind the next sectionalizing CB [Chi 04] or busbar [Fri 01]thus providing back up protection for the next CB. The downside of this is that therewill have to be an appropriate delay in the second zone which will lead to delayed faultclearing in case a fault at the end of the protected line [Fri 01] (the delay will still oftenbe less than the delay of zone two in ring networks because once the first relay hastripped, all the fault current will be fed from the other end which increases the faultcurrent seen by the other relay). This downside can, however, be overcome with an endto end communication channel arrangement which is widely used in transmissionnetworks [Zie 06]. In this case, a communication channel which can be based on manytechniques, such as PLC, optical fibres, pilot wires and so forth, is established betweenthe sequential distance IEDs. In the occurrence of a fault at either end of the line, therelay that “sees” the fault on its first zone will trip without a delay and signal the relay atthe other end that “sees” the fault on its second zone, to do likewise. [Zie 06] The thirdzone, which is often not used in distribution networks, might be set to trip with a delaywhich is just below the thermal breaking point of the equipment in the zone. [Fri 01]

Distance relays have many benefits. They, unlike the directional overcurrent relays,are unaffected by the changes in network or generation conditions. Distance protectionscheme is also more economical compared differential protection scheme, which

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requires two measurement points and relays as well as appropriate communicationbetween the two points. [And 99] It is also beneficial that distance protection relaysenable rapid fault clearing while maintaining the selectivity and provide a back upprotection for some parts of the network because of their multiple protection zonearrangements. Distance relays, nevertheless, do also have some disadvantages such astheir inability to detect earth faults in isolated neutral and impedance earthed systems,which for example, are used in Finnish distribution networks. Another disadvantage isthat distance relays do not suit well for protecting lines less than 10 km long and thattheir operability is deficient in high resistance earth faults as well as in conductor phasefailures. [Mör 92]

5.2.4. Differential protection scheme

Configuring conventional overcurrent and distance protection relays for protecting shortlines, particularly the ones close to longer lines, may sometimes be problematic. Inorder to ensure selectivity, these protection schemes may have to be adjusted to tripwith appropriate delays. This is harmful because the delayed fault clearance causesstresses to the equipment in the faulted network. [For 04] Such problems with delayedoperation could be solved by utilizing differential protection because it providesabsolutely selective operation, in other words, it detects faults only within its area ofprotection. Differential protection relays can, therefore, be set to trip very rapidly andwith high sensitivity. [ABB 00, And 99]

Differential protection is based on measuring the currents from both sides of theprotected element which can be a component or a line. During normal operation thedifference between the currents measured before and after the element is zero. If a faultshould occur on the protected area a difference in the current amplitudes or phase angleswould be born. The protective relay is triggered if the difference between the measuredcurrents or amplitudes is greater than the triggering setting value. In order to avoidmeasurement errors caused by the current transformers, the triggering value isproportional to the measured current. In other words, as the measured current increases,so does the required difference between the currents needed for the triggering. Since thisprotection scheme is based on comparing the measurements of each end to each other,appropriate communication arrangement is, of course, necessary. Usually thecommunication channel between the IEDs is also supervised. [And 99]

Meshed and ring type networks often require unit protection schemes which,however, can as well be applied in radial networks including DG. [ABB 08c] Unitprotection stands for a concept where protected area consist of everything inside themeasurement points (two or more). Such an arrangement could, for example, consist ofthree IEDs based on differential protection with respective communicationarrangements between each other. The IEDs would then be measuring all the currentsentering the protected zone and all the currents exiting the zone. During normaloperation there would, of course, be no difference between the currents, whereas, during

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a fault inside the protected zone the case would be the opposite. [And 99] The idea ofunit protection is presented in the figure 5.3 where the protected are is marked with adashed light grey line.

Figure 5.3. The idea of unit protection

Differential protection is, nevertheless, not the most suitable protection scheme fortraditional radial overhead distribution networks that contain loads all over the feeders.This protection scheme is best suited for protecting cable lines supplying single loads ora DG unit at the end of the cable. Also feeders that contain only generation and no loadsat all could benefit from the use of differential protection because differential protectionis immune to the protection blinding and protection selectivity problems. Failedreclosing problems are also eliminated if the DG units are situated at the end of a feederthat is completely protected by two differential IEDs.

5.2.5. Loss of mains protection methods

LOM protection methods can be categorized into passive internal, active internal andexternal methods. The internal methods are based on monitoring the electrical quantitiesand thereby detecting the island based either on detecting the transients that often occurduring the start of an island or on the change in the system size. Most of these methods,unfortunately, have a non detection zone where they are unable to detect the start of anisland. [Sam 07]

The internal passive methods include under/over voltage-, under/over frequency,voltage phase jump-, rate of change of frequency- and voltage harmonics protection.They are popular because of their low implementation cost and applicability to all units.All the other internal passive methods except voltage harmonics assume that there willbe an unbalance between the production and consumption of active or reactive power inthe islanded zone that can be detected. Internal active methods, on the other hand, arebased on manipulating some system quantity which is only possible in a small systemsuch as in a power island. Impedance measurement, Slip mode frequency shift,frequency bias, sandia frequency shift, sandia voltage shift and frequency jump belongto internal active methods. They are popular in units with a power electronic interfacebecause such units are capable of manipulating the electrical quantities withoutadditional cost. Internal active methods, unlike the passive internal methods, are capableof detecting balanced islanding. The downside is that when a high amount of units close

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to each other are protected with internal active methods, they start to interfere with eachother. The power quality may also be deteriorated by the manipulation of voltage. [IEA02, Sam 07] A more detailed description of these LOM protection methods can befound from [IEA 02]. External LOM protection methods, which include power line carrier-, disconnectsignal- and SCADA methods, all involve the utility. These methods are not based onmonitoring electrical quantities and thus, do not suffer from the non-detection-zoneproblem. The power line carrier method is based on an arrangement where subharmonicsignals are sent from a central location and DG units assume normal conditions as longas they receive these subharmonic signals. If a breaker upstream from the DG unitlocation is opened, the DG unit will no longer receive the subharmonic signals and istripped off immediately. The second method, namely disconnect signal method, is basedon an arrangement where the switches in the network will send a trip signal downstreamwhenever they are opened. This, however, requires large amounts of transmitters sinceall the switches that might cause an island will have to be equipped with one. In theSCADA method, the idea is to extend the control range of SCADA to all the DG unitsso that they can be centrally tripped off the grid as soon as an island is detected. [Sam07] The SCADA method is, however, rather slow especially when it is busy with manyevents from one or multiple disturbances [Str 05], which makes it more suitable forbackup LOM protection purposes.

5.2.6. ROCOF based LOM protection

Vector shift and Rate-of-Change-of-Frequency (ROCOF) are probably one of the mostutilized LOM detection methods. The latter LOM protection scheme will be discussedmore closely because the functioning of real ROCOF relay will be examined in chapterseven. ROCOF is based on power imbalance as it can be seen from equation 5.1, whichis derived from generator swing equation. PG (pu) represents the power generation onfeeder, PL (pu) is the consumption on the feeder, H (s) is the inertia constant of thegenerator and fS (Hz) is the system frequency. [Jen 00, Raj 04]

dtdf

fHPPs

LG2 (5.1)

The paper [Raj 04] examined the effect of reactive power on ROCOF based LOMprotection. A case was studied in the paper, where a DG unit using a synchronousgenerator operated at unity power factor, was connected to feeder with a slightly greateractive power demand compared to the DG unit output. It was found out that powerfactor of load on the feeder had a significant impact on ROCOF. This stems from thefact that the voltage would always drop during the initial phase of the island transition ifthe power factor of the load was less than unity. The voltage drops initially because of

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the inability of the voltage regulator of the generator to respond rapidly enough to thesudden reactive power demand caused by the transition to an island. The reducedvoltage level, in turn, leads to reduced consumption in the loads located in the islandedzone which, of course, reduces the power imbalance. The reduced power imbalancemay even lead to the prevented operation of ROCOF based LOM protection. [Raj 04]

Also the type of the load affects the performance of ROCOF based LOM protection.This can be clearly seen from figure 5.4 which represents the tripping times of aROCOF relay with a setting value of 1,20 Hz / s versus the power imbalance betweengeneration and demand in an islanded zone. The behaviour of constant power, constantcurrent and constant impedance loads is discussed more in detail in chapter six.

Figure 5.4. The effect of load type on a ROCOF relay with a 1,20Hz / s setting [Aff 05]

The curves in the figure are from a simulation that was undertaken in a British style MVnetwork model with a nominal frequency of 60 Hz. The network model included one30 MW rated synchronous generator which was operated at unity power factor. Figure5.5 represents the network that was used in the simulations of the paper.

Figure 5.5. Single-line diagram of the network that was used in the simulations of [Aff05]

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According to the simulations carried out in this network model, constant impedanceloads are most troublesome to detect with ROCOF relays when there is deficit of powerin the island zone. When an islanded zone has excess of active power, however, theinitial power imbalance is increased due to the reduced demand which is caused by theinitial voltage dip. In such case, the ROCOF relay actually operates faster when theloads are of constant current or constant impedance type compared to a situation wherethe loads are of constant power type. The performance of ROCOF is also affected by theinertia constant of the generator. The bigger the inertia constant is the slower thegenerator responds to the islanding situation and consequently the longer it takes forROCOF to detect the islanding. [Aff 05] From the protection point of view, it wouldthus be desirable to have a small inertia constant, whereas, from the system stabilitypoint of view (TSO point of view) large inertia constants are favorable.

5.2.7. Communication between feeder and generator protection

As already discussed, most of the LOM protection schemes are prone to the NDZproblem. The paper [Rin 08] suggests that the NDZ problem could be tackled if fast andreliable communication between the IEDs on the feeder and the IEDs protecting the DGunits were established. In such a case, the IED commanding the feeder CB open couldsimultaneously order the IEDs protecting the DG units to trip thus avoiding the possibleunintentional islanding situation. Establishing a reliable LOM protection with the helpcommunication between the IEDs is illustrated in figure 5.6. [Rin 08]

Figure 5.6. Communication arrangement between feeder and DG unit protection [Rin08]

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The communication between IEDs on the same substation is accomplished using thefast and reliable GOOSE (General Object Oriented Substation Event) messagingprovided by the IEC 61850 standard. The communication between sequential IEDs (forexample the two RED615 IEDs in the figure 5.6), on the other hand, is established viathe so called Binary Signal Transfer (BST). IEDs containing BST ability have 8 bi-directional bits reserved for user defined communication purposes. If the switch 2Q0 infigure 5.6, which is connecting the substation A to the grid, should be opened, forexample due to a human mistake, the REF615 IED would register this and send theinformation forward to the RED615 IED on the same substation via GOOSE message.The RED615 would then pass the message further to the other RED615 at the end of theline using BST, which in turn, would signal the message to the IED protecting the DGunit via GOOSE. This way the islanding would be reliably avoided and, moreover, thiswhole signal transfer process would take less than 30 ms time. [Rin 08]

5.3. Automatic control system (decentralised)

5.3.1. Frequency control

Different types of power production all have their own technical and economicalcharacteristics, which govern the way they are used. The amount generation dispatchedeach hour is based on load predictions that are made one day in advance for every hourof the following day. The hourly load predictions are relatively accurate but there willusually still be some unbalances between the production and consumption. In order tobalance these deviations, generators are dispatched more precisely for every 15 minuteperiod one hour in advance. These power deliveries are handled in special regulatingpower market. Changes in the load occurring faster than in 15 minute periods, however,are not predicted at all. The balancing of these deviations, which should be relativelysmall, is left for the frequency control. [Ple 03]

Frequency control consists of two components, namely primary and secondarycontrol. The power plants attending the primary control all have to be equipped withturbine governors with automatic frequency controllers. These controllers are fast andtheir gain is selected in such a way that the power required is divided between theparticipating generators proportionally to their capacities. [Ple 03] If a deviation in thepower balance of the system should take place, the rotational masses of all thegenerators will either absorb or release kinetic energy, which results in a change in thesystem frequency. This is called the inertial response. If the frequency deviation is largeenough, the primary frequency control is activated. [Mor 06] After the primary controlhas compensated this power unbalance, there will still be a deviation in the systemfrequency. If this deviation is large enough, secondary control reserves are activatedwhich will bring the frequency back closer to its nominal value, and thereby free theactivated primary reserves for prospective needs. In the NORDEL power system

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(includes the Finnish, Swedish, Norwegian and the eastern part of the Danish powersystem [Nor 08]) Primary control is automated whereas secondary control is manual.[Ple 03] The same practice is also used in the national grid of UK [Ile 04]. Figure 5.7illustrates the roles of primary and secondary frequency control. The operation times forprimary and secondary control in the figure represent the British requirements.

Figure 5.7. Primary and secondary frequency response [Ile 04, see Nat 04]

Wind power is problematic in the sense that its production is difficult to predict and thatthe production does not correlate with the demand. This leads to the fact that additionalreserve capacity is needed if the proportion of wind power is high. If wind power is toreplace some conventional power plants it may be necessary that wind power has tobecome a part of the control reserve. In order to be able to control the frequency up anddown, wind power must be set to operate on lower than full capacity. This, of course, isa waste of energy and thus increases the cost of the energy produced by wind power.The use of conventional regulating power plants (hydro power and gas turbines) andenergy storages with adequate capacity, as for instance pumped hydro energy storageand large scale storage of hydrogen combined with fuel cells, could solve this problem.Present hydrogen storages combined with fuel cells unfortunately have the disadvantagethat the efficiency of their charge-discharge cycle is less than 50 %. [Ple 03]

There will also have to be additional disturbance reserve for contingencies where ageneration unit or an interconnection is suddenly lost. The size of the requireddisturbance reserves is determined by the largest generation unit or the interconnectionwith the largest imported power flow. [Ple 03] Load control, which will be presentedlater in this thesis, has very favourable characteristics for being used as this kind ofcontingency reserve. By using load control as reserve capacity the generators allocatedfor reserve capacity could be liberated from this task to be used for power production.Loads containing an energy reserve of some kind are most suitable for load controlpurposes because the use of such loads causes least harm for the customers. [Kir 99]

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The generation units attending to the provision of a certain service need have sufficientperformance for meeting the requirements. The requirements on the performance, inother words, response times in the case of frequency control services, depend onwhether the requested service is for continuous frequency control or for disturbancereserve purposes. The response time characteristics of DG units depend on the source ofpower of the generation unit like wind, hydro, gas and so forth. [Rau 08]

Many DG units are connected to the network through power electronic converters.These sorts of units are separated from the system frequency and are, therefore, allowedto operate on whatever speed is optimal for them as, for example, the variable speedwind turbines and the micro turbines do. Some DG units, like fuel cells or photovoltaic,have no rotational parts at all. Units with a power electronic converter connection,therefore, require special arrangements in order that they could participate to frequencycontrol. Such arrangements are presented in [Mor 06], where the frequency controlcapabilities of different kinds of DG units are also examined. Wind turbines cannotparticipate in the primary frequency control in the classical sense, unless they areoperated on lower than full output power as explained earlier. They, however, arecapable of either rapidly releasing or absorbing energy from/to their rotational mass thuscontributing to the frequency control for a short period. Fuel cells, on the contrary, arenot capable of rapid power output changes but, on the other hand, they are capable ofsustaining the slow increments made in their power output. In that sense, these two areof somewhat complementary. Micro turbines, which are basically small gas turbines,are, of course, capable of primary frequency control as long as they are not operating attheir full power. [Mor 06] Small-scale hydro-generation suits well for frequency controlprovided that the unit includes a reservoir of a considerable capacity. Withoutconsiderable storage capacity the output of hydro-generation unit is dependent on theriver flow and is thus likely to undergo large variations. [Jen 00] Small scale combinedheat and power (CHP) unit are usually set follow the heat demand and the electricity isthus only a by-product that is being produced in proportion to the heat production. Theproduced heat and electricity in a CHP unit including a heat accumulator can, however,be decoupled to some extent depending on the capacity of the accumulator. [Ple 03] Allin all, there should be a mixture of different kinds of DG units in order that the DGcould obtain a good contribution to the primary frequency control. [Mor 06]

DG units attending to the provision of primary frequency control service areoperated according to specified power-frequency (droop) characteristics. The droopdetermines the dependency between the system frequency and the real power output ofthe generation unit. This simply means that the generation unit has to increase its realpower output when the frequency decreases below its nominal value or, respectivelyincrease its output power when the frequency increases above its nominal value. Figure5.8 illustrates the functioning of two droop curves. In figure 5.8 a, a droop curve formeant for primary frequency control is illustrated, whereas in figure 5.8 b, the form of a

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droop curve meant for generation units attending disturbance reserve services is shown.[Rau 08]

Figure 5.8. The real power–frequency (Droop) characteristics of a DG unit. a) Primaryfrequency control b) disturbance reserve control [Rau 08]

VPP can aggregate the capacities of multiple DG units and sell this as one service to theTSO. The characteristics of this service are determined by the sum of the characteristicsof all participating units. The offered service can be either a primary- or secondaryfrequency control service, or it can also be a combination of from the two. Theaggregated generation capacity of controllable DG units and loads has to be significantbefore the ancillary service in question has any relevance. One should note that specialattention has to be paid to the functioning of LOM protection when DG units andcontrollable loads are attending to the provision of primary frequency and frequencyresponse services. This is because the reliable establishment of LOM protection basedon over/under frequency or ROCOF is more difficult in network sections containingconsiderable amounts of active resources capable of maintaining the frequency close toits nominal value. [Rau 08]

DG units could also participate in the secondary frequency control service marketwith the help of VPP. The Finnish TSO Fingrid requires that the minimum generationcapacity that can be offered in the regulating power market is 10 MW and that thecapacity has to be available during the whole hour [Fin 09c]. VPP can, however, enablethe participation of smaller resources by aggregating the capacity of multiple resourcestogether and offering the aggregated capacity as one. When the VPP is ordered toexecute a service like this, it sends control commands to the units attending to theprovision of the service. [Rau 08]

5.3.2. Active voltage control

Voltages in distribution network alter mainly in proportion to demand but changes innetwork configurations also affect the voltages. Appropriate voltage controlarrangements are needed because of the constantly varying voltages and therequirements to maintain the voltages within predefined limits. OLTCs in the HV/MV

55

transformers which control the substation busbar voltage based on local measurementshave commonly been a sufficient measure for the voltage control of distributionnetworks. [Lak 95] DG, however, complicates the control of voltage levels as alreadydiscussed in chapter three. High DG penetration level may even render the conventionalvoltage control methods inadequate. This problem can be overcome by the use of activevoltage control which offers a wide range of new solutions. [Kul 07]

Active voltage control can be divided into two hierarchical levels, namely the localand the coordinated voltage control. The local control is based on local measurementsand controllers which regulate the voltages at their operating points by controlling theactive resources such as DG units and reactive power compensators. Voltages can alsobe regulated by controlling loads and, in extreme cases, by curtailing the DG unitproduction. Coordinated voltage control, on the other hand, makes its control decisionsbased on measurement data concerning the whole network that is under its supervision.Coordinated control can regulate the network voltages solely by controlling the OLTCsituated at the substation or by the combination of all the resources capable of voltagecontrol. Communication channels between the network nodes are, of course, needed fortransmitting the measurements from various locations and for sending controlcommands to the participating active resources. [Rep 05a, Kul 07]

The following chapters present four local voltage control strategies. These are thereactive power control of the DG units, load control and finally production curtailment.After these, also the coordinated voltage control method will be presented

5.3.3. Reactive power control of the DG units

DG units that are operated on unity power factor control irrespective of the networkconditions usually complicate the voltage profile management of the DNOs. Thecommon problem is the voltage rise at the connection point of the DG unit which,according to passive network management, necessitates costly network reinforcements.Instead of executing such costly reinforcements, which may either render the DG unitinvestment uneconomical or just cause the network fees to rise depending on theallocation of the costs, the voltage rise problem can usually be avoided by simplycontrolling the power factor of the DG unit appropriately. [Ack 05] This is a fairlyattractive solution since many of the DG units are already capable of continuous powerfactor or voltage level control. This type of control is based on local measurements andcontrollers, which try to maintain the voltage at the unit terminals within permissiblelimits. [Rep 05a] The local controllers can, however, also change their control modeback to normal power factor control at times when the voltages at the DG unitinterconnection point are within permissible limits [Kul 07].

The idea of this approach is to control the reactive power production/consumption ofa DG unit or a reactive power compensator which, in turn, affects the voltage at theinterconnection point. Reactive power control in the DG units can be achieved by powerfactor correction in case of induction machines, excitation system in synchronous

56

machines and reactive power in applications connected through frequency converters.This control possibility is, nevertheless, generally not being used at present because ofthe restrictive interconnection contracts that only allow a rather narrow range for thefree-of-charge power factor. [Rep 05a]

The DNOs should, however, bear in mind that relatively large reactive power flowsmight be needed to mitigate the local voltage rise caused by real power generation sincedistribution networks commonly have low X / R ratios. Increased reactive power flows,in turn, require higher thermal capacity, cause bigger network losses, increase theburden on VAr sources and might interfere with the power factor sensitive tap changerschemes. [Sco 02] The reactive power control of DG units is, nevertheless, a potentialalternative to network reinforcements, especially if the voltage rise problems areoccasional. [Rep 05a]

5.3.4. Power electronic compensation

Voltage rise, power quality and power system stability issues can sometimes restrict thepenetration of DG resources as already discussed. FACTS (Flexible AC TransmissionSystem) devices such as SVC (Static Var Compensator) and STATCOM (StaticCompensator) can be used as a means to tackle such restrictions. A typical SVCnormally includes thyristor controlled reactors (TCR), thyristor switched capacitors andharmonic filters for eliminating the harmonics created by the TCR. Figure 5.9 illustratesthe shape of an SVC scheme. The compensation capacity can be optimized according toutility preferences, in other words, the compensation capacity can be symmetric orasymmetric to either inductive- or capacitive directions. The capacity of a voltagesource converter (VSC) could thus, for instance, be 100 MVar inductive and 200 MVarcapacitive. [Nor 03] An SVC can, for example, be used for giving reactive powersupport to wind farms in steady state as well as in transient disturbance conditions aspresented in [Grü 08].

Figure 5.9. A Static Var Compensator configuration [Nor 03]

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The performance of STATCOM is similar to SVC but it has some advantages comparedto SVC such as compactness, faster control and independence of current injection fromthe voltage. [Eri 00, see Mai 07] The last mentioned is important for compensatingvoltage dips. STATCOM’s make use of VSCs, which are capable of producing orconsuming active and reactive power. Figure 5.10 presents a picture of a three phaseVSC configuration [Grü 08]

Figure 5.10. A three phase voltage source converter configuration [Grü 08]

As illustrated in the figure, a VSC configuration consists of a capacitor bank connectedthrough a converter bridge. VSC acts as voltage source that is capable of controlling thevoltage phase, frequency and magnitude at its interconnection point. [Grü 08]

5.3.5. Load Control

The ability to control customer loads is a promising solution for voltage and frequencycontrol purposes. Load control is based on switching controllable loads either on to filldemand minima’s during periods when the DG power generation is high or off to cutthe peak demand respectively when DG production is low. Voltage fluctuationsoriginating from, for instance, wind generation can also be tracked and tackled by fastdynamic load switching. [Sco 02] Load control can also be used for aiding DG units thatdo not have sufficiently rapid response times for attending to the provision of certainfrequency control services. This could be done by combining a group of DG units andcontrollable loads as one service in which controllable loads are switched off during theearly phase of the frequency control action in order to speed up the response of theservice. This of course has a raising effect on the frequency. The loads that wereswitched off can later be switched back on when the DG units have reached the desiredlevel of production. [Rau 08] Loads that are capable of storing energy, such as thermal-,cooling- and pumping loads, are the most suitable ones for load control. This stems

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from the fact that turning such loads on or off basically causes no inconvenience to thecustomers since the energy can be used stored for later use. [Rep 07]

The control of the loads can be based on centralized management system combinedwith fast and reliable communication links, or it can alternatively be based on localintelligence and measurements like frequency, voltage, ROCOF and the combination ofROCOF and frequency [Del 01, Rep 07]. Fast and reliable communication links arerequired for certain purposes like for controlling the power flows, whereas, for somepurposes like the management of the billing related to load control, the speed of thecommunication link is not an issue [Rep 07]. The AMR devices, which in manycountries are now being installed in increasing numbers, provide a very promisingalternative as a communication medium for load control [Jär 07]. One must ensure thatthe load capacity that is switched off is not too large when local frequencymeasurements are used as the command variable for the loads. This can be done bygrading the frequency thresholds of the controllable loads in a suitable manner, whichsimply means that the reduction of demand is proportional to system frequency. [Rep07] The control strategy of the loads can either be simple on-off type or it canalternatively be continuous. Continuous control, in this case, means that theconsumption of the load in question can be varied from nominal demand to zero in acontinuous fashion. Continuous control is usually better because it gives smootherresults and takes better into account the constraints related to the control of customerload in question. [Sam 97, Rau 08]

One way to establish load control is the use of dynamic demand control (DDC)which means that loads are made frequency dependent. When space heating loads arecontrolled according to DDC, the setting values of the thermostats in question arefrequency dependent. The load capacity that is to be switched off/on during a frequencydeviation is thus proportional to system frequency. The space heating customer can,nevertheless, be guaranteed a minimum temperature after which the heater is switchedback on. This means that the available controllable load capacity is thus also dependenton outside temperature, the heat insulation and the desired minimum temperature. Theutilization of DDC control requires that the thermostats are frequency dependent whichis not the case at present. It is, nevertheless, fairly simple and inexpensive to add thisfeature to new thermostats. Special attention should be paid to the coordination of DDCcontrolled loads as it is likely that their number will be considerable. AMR devicesprovide a valuable tool for the coordination. [Rau 08]

The need for load control is infrequent because of the occasional nature of voltageand frequency disturbance problems. This leads to the fact that the payback time for theassets needed for load control devices can be relatively long. In order to improve theeconomical attractiveness of load control, the other possibilities provided by loadcontrol should also be harnessed. The other functionalities include, for example, thepossibility of taking advantage of the low electricity cost periods, avoiding line overcurrents and alleviating LV network undervoltage problems. All in all, load control is apotential alternative for enabling larger amounts of DG to be interconnected, although

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the contracts may become of somewhat complicated as there are three parties, namelythe generator, supplier and distributor, involved. [Sco 02]

5.3.6. Production curtailment

In extreme network conditions, which should only rarely occur, the production could becurtailed in order to prevent excessive voltage rise. The production curtailment termscould be agreed with the DG unit owner either in the interconnection contract or in anancillary service contract. This method is fairly simple in hydro power and CHP plants,where the turbine set-value adjustments are easily carried out. CHP plants are, however,not quite as suitable as hydro power plants because the CHP operation is stronglygoverned by the heat demand. Some CHP plants have heat storages which make itpossible to separate the heat and electric power production to some extent. The electric /heat power ratios are also usually adjustable but the plant efficiency tends to degrade ifthe ratio is reduced. [Rep 05a]

The easiest way for wind power curtailment is to disconnect a proper amount ofunits when the permissible voltage level is exceeded. The unit disconnection can bebased on voltage relays, which either have different upper voltage values or trippingdelay times, installed to the unit interconnection points. Variable speed and pitchcontrolled wind power plants can, nevertheless, also be controlled continuously by afrequency converter or blade angle control. These sorts of wind turbines do not thushave be necessarily disconnected from the network. [Rep 05a]

5.4. Area control level (centralised)

5.4.1. Coordinated voltage control

Coordinated voltage control method uses data concerning the whole network under itssupervision for the optimization of the control. Extensive network monitoring and datatransfer between the network nodes are thus necessary for the utilization of this method.[Kul 07] Figure 5.11 represents the idea of the coordinated voltage control. It is basedon adjusting the HV / MV transformer voltage set-value according to the measurednetwork voltages. In practice, the voltage coordination means utilization of the voltagemargins between the minimum voltage of the network and the minimum permissiblevoltage and likewise between the maximum voltage of the network and the maximumpermissible voltage. [Rep 05a]

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Figure 5.11. Available voltage drop and rise margins [Rep 05a]

Network voltages are controlled by the operation of the substation OLTC which, in turn,is controlled by the automatic voltage controller relay (AVC relay). The operation ofOLTC alters the substation voltage and thus also the voltages on all the feeders fed bythe HV / MV transformer where the OLTC is mounted. Voltage drop margin is,therefore, determined by the minimum voltage in the whole network in question and theminimum permissible voltage level. Usually the minimum voltage on a lightly loadednetwork can be found from the end point of a feeder where no DG units areinterconnected. If a voltage rise problem at a DG unit interconnection point caused byhigh production should occur, the AVR relay can order the OLTC to utilize the voltagedrop margin, and hence reduce all the voltages fed by the HV / MV transformer(s) inquestion. This way the DG production may be allowed to be higher than in case ifcoordinated voltage control was not utilized. [Rep 05a] Network reinforcements neededbecause of the voltage rise effect caused by the connection of new DG units can also beavoided in many cases when coordinated voltage control is applied [Kul 07].

Figure 5.12 illustrates a way by which the OLTC can be controlled whencoordinated voltage control is applied. The available voltage rise and drop margins canonly be utilized if network condition requirements presented in the figure are met. This,for instance, means that the tap changer cannot be set to raise the substation voltage if itcauses the voltage elsewhere in the network to exceed the allowable limits. Naturallythe OLTC cannot either be used for raising the network voltage if its set point is alreadyin the maximum. A delay element is also included in the control algorithm of the figurein order to avoid unnecessary operations during short voltage variations. Coordinatedvoltage control, nevertheless, increases the number of operations of OLTC whichincreases the maintenance costs of OLTC. The avoided reinforcement costs are,nonetheless, most likely to offset the increased maintenance costs of OLTC. [Kul 07]

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Figure 5.12. The operation principle of OLTC in coordinated voltage control [Kul 07]

The measurements needed along the network can be carried out by remote terminalunits (RTUs) or AMR devices that have measurement, communication and controlcapabilities. Coordinated voltage control can also be used together with the localvoltage control methods that were already discussed earlier. The communication systemrequired strongly depends on the complexity of the voltage control method being used.If a coordinated control method is used together with local voltage control schemes,communication mediums between the RTUs, the DMS and the AVR are needed. [Str02]

5.4.2. Power flow management

This chapter briefly presents the idea of power flow management. The ideas presentedin the following are to be utilized in meshed networks or in networks that are fed bysubstations with two or more main transformers. Figure 5.13 illustrates a typical Britishnetwork, where power flow management could be applied. A real life demo thatillustrates the functioning of power flow management is also discussed afterwards inchapter 5.7.1.

Managing the distribution network power flows can be used as a means to increasethe amount of DG that can be connected to the network. The power flow managementconcept is based on segregating the network into zones and controlling the power flowsbetween the zones so that the network transfer capacity will not be exceeded. This, ofcourse, necessitates power flow measurements between the zones. The concept dividesgeneration into three categories, namely firm capacity (FG), non-firm capacity (NFG)and regulated non-firm capacity (RNFG), which all are controlled according to theirown ways. [Aul 06, Cur 07a]

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Figure 5.13. A network suitable for the utilization of power flow management [Cur 07a]

FG represents the DG units that are always allowed to operate at their full output power.This means that the FG units are allowed to produce their full output even in the case ofa fault in the line with the highest transfer rating, while at the same time theconsumption is at its minimum (N-1 contingency). Therefore, it is clear that thepermissible DG penetration level will be fairly low if the level is not allowed to exceedFG, and there will, obviously always be spare transfer capacity in the network duringnormal operation. [Aul 06, Cur 07a] This sort of design principle causes no risk for thenetwork operator but it will greatly limit the amount of permissible DG production [Col03]. In the example network of figure 5.13, the FG would equal to 14 MVA which isderived from the situation where the transfer capacity to upstream network is reduced to12 MVA (other transformer / line is out of service) and where the demand is only 2 MW(at its minimum).

As already noted in the earlier chapters, the level of allowable DG can be raised byreinforcing the network but it can be very costly. The allowable capacity can also beraised by using the network more efficiently, in other words, using the spare capacitythat would be unused if only FG was allowed. The NFG units are allowed to operate asthey wish during normal operation, but during abnormal contingencies, the NFG unitsare trimmed or tripped depending on the required power reduction. [Col 03] Themathematical definition of NFG can be described as the transfer capacity of the circuitsplus minimum load minus FG. [Cur 07a] Again, in the example network of figure 5.13this would equal to 12 MVA (= 24 MVA + 2 MW – 14 MVA).

Some of the FG and NFG units may be intermittent which means that they do notoperate at their rated output all the time. Similarly, the load is at its minimum onlyoccasionally. This leads to the fact that most of the time there would be room for evenmore production in the network in addition to the FG and NFG units. The remaining

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extra space could be used by the RNFG units, which are subject to constraining ortripping whenever the network conditions require it. The constraining and tripping aredone according to the defined operating margins which take account the variability ofthe load and generation. These operating margins have two boundaries. On the firstlimit, namely the trim margin, trimming orders are sent to the RNFG units. Thetrimming commands are based on the highest rate of change in the power transfer fromthe zone and the operating delay of the trimming order. If this is not enough, RNFGunits within the zone are ordered to be tripped. [Cur 07a] The generation unit that aresubject to constraining in certain circumstances, in other words NFG and RNFG units,need to be equipped with hardwired intertripping/trimming facility so that they can berapidly controlled when needed [Aul 06]. The theoretical capacity of RNFG is definedas the maximum transfer capacity of the circuits plus the maximum load minus the sumof FG and NFG. In reality, however, the limiting factor of RNFG comes fromeconomical considerations rather than from the theoretical limit. [Cur 07a] The RNFGcapacity equals to 10 MW (=24 MVar + 12 MW – 14 MW – 12 MW) in the examplenetwork of figure 5.13.

Active power flow management has the potential to lower the connection costs forgeneration units that, according to their connection contracts belong to the NFG orRNFG units. On the other hand, active power flow management also leads to reducedelectricity production for NFG and RNFG units which means reduced incomes. Theinvestors will thus have to assess the economical advantages and disadvantages ofconnecting their units using this approach. In the case of NFG units, the risk of beingconstrained is, nevertheless, rather small which should make this approacheconomically attractive to investors. [Aul 06]

5.4.3. Automatic network restoration

Automatic restoration has generally speaking three objectives. These are to restore thesupply to as many customers as possible as quickly as possible and accomplishing thesetwo targets using as small number of switching as possible. [Ver 97] Temporary faults,such as earth faults caused by lightning strikes on the overhead lines, are cleared byautomatic reclosing leaving no need for further measures. Typically, in case if the firstreclosing should fail, one or two more reclosings are made before the CB is ordered intoopen position after which the restoration process can begin. [Lak 08, Ple 03] Restorationprocess can be divided into two parts. The first phase aims to find out an optimalrestoration configuration while the second part consists of the actual switchingoperation required for the desired configuration. The idea in the first phase is tominimize the number of un-served customers and the outage time while paying attentionto the possible constraints. [Chin 05] The constraints include factors such as thermalloadability (limited transfer capacity), the functioning of network protection andpossible violations in voltage limits [Lak 08]. In small power systems like power islands

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one will also have to take into account the possible limitations concerning availablepower sources.

An estimate on the fault distance is achieved by comparing the recorded faultcurrents with the fault currents computed by SCADA / DMS. This requires thatnumerical relays or separate disturbance recorders, that are capable of recording andsending the fault currents to SCADA / DMS, are used. Distribution networks usually,however, have many branches, which often leads to a situation where there are multiplelocations on different branches whose calculated fault current equals to the measuredfault current. In situations like this, additional information like information from faultcurrent indicators, information on the conductors (overhead line or cable), informationfrom lightning positioning systems, weather information (wind speed and its direction),information on the surroundings of the line (forestry surroundings, snow load onconductors) have to be used for determining the most probable fault location. Fuzzylogics, which enable the utilization of uncertain information, can be utilized whenreasoning out the most probable location. The fault locating has proven to be a reliableand very useful tool for estimating the location of short circuit faults but furtherdevelopment is needed for earth fault location estimation (in networks with isolatedearth and impedance earthed systems) . [Lak 08]

Once the most probable fault location has been determined, the second phase,namely the switching procedure can begin. The remote controlled disconnector nearestto the assumed fault location is opened for isolating the end section of the radial feederafter which the CB protecting the feeder in question is closed for re-energizing thefeeder. If the CB remains closed, the fault is located at the end section as assumed but ifthe CB is opened, the fault is located upstream from the opened disconnector. In thefirst case, the supply to the non-faulted section can be continued and it may also bepossible to re-energize part of the end section of the feeder (behind the faulted section)if it is possible to isolate it from the faulted part and if sufficient back up connectionsexist. In the latter case, the “zone by zone rolling” method can be used for finding theactual fault location. In this method, the zones (separated by remote controlleddisconnectors) are connected one by one starting from the beginning of the feeder inquestion. Once the CB protecting the feeder opens, the faulted zone is found and it canthen be isolated. The supply can then be restored to the healthy part. [Jär 95] Theswitching procedure for remote controlled switches can be completely automated andleft for the DMS to carry out. Some engineers, nevertheless, are of the opinion that thesoftware should only have an advisory role, whereas the actual switching operationshould be in the hands of the operator. [Leh 01]

5.4.4. Island operation

Islanding refers to a situation where a zone including DG in a distribution network isisolated from the main system, for instance, as a result of a fault elsewhere in thenetwork. The electricity supply to the customers in this power island zone does not

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necessarily have to be interrupted at all if island operation is allowed and it is utilized.This, however, requires that the DG units in this zone are capable of meeting thedemand and maintaining the zone voltages and the zone frequency within thepermissible limits. It is also necessary to arrange a suitable and reliable protection in theislanded zone. [Pre 03]

The sequence leading to islanding usually begins by the operation of protectionsystem after a fault. The DG units are also disconnected for the time that the systemprotection needs for isolating the faulted part of the network. This is followed by the re-connection of the DG units and the island zone is thereby formed. Eventually, after thefault located elsewhere in the network is fixed, the islanded part will be synchronizedwith the main system frequency and re-connected to it. [Pre 03]

The utilization of intended islanding can significantly increase the reliability of thepower supply in areas that are capable of operating as an island. In order to harness suchreliability benefits, one must pay special attention to the placement of remote controlledswitches. This stems from the fact that the island zones must have adequate generationcapacity. Also the nature of the DG units will have to be taken account. [Pre 03] Apower island containing only DG units based on intermittent primary energy such aswind obviously cannot operate properly, [Pre 03] unless energy storages or othercontrollable energy resources with sufficient capacity are available. The placement andthe reliability of the DG unit(s) in question also have a significant effect on thereliability [Ant 08].

The fault currents may be remarkably smaller in island operation compared to thefault currents in normal operation due to the reduced short-circuit capacity connected.This leads to prolonged fault clearance times and difficulties in coordinating theprotection settings in the islanded zone because of the reduced difference between load-and fault currents. One way to solve this problem is to switch to different relay settingsduring island operation. The settings could then be changed back when connecting thepower island back to the main system. [Ple 03]

The type of the generators in a power island also has an effect on the functionality ofthe protection in the power island. As already discussed in chapter 3, inductiongenerators, unlike synchronous generators, are not capable of feeding sustained shortcircuit current. This raises so grave challenges for arranging selective short circuitprotection in a power island containing only induction generators, that it is more likelythat unselective short circuit protection is to be adopted in such power islands. The fact,that the benefits of selective short circuit protection in a power island containing onlyinduction generators is nullified because of the poor short circuit FRT capabilities ofinduction generators, also favors unselective short circuit protection. Selectiveprotection, however, is beneficial in the sense that the faulted part of the power islandcould automatically be isolated making the healthy part of the power island ready for anew black start. Selective earth fault protection is, however, more easily achieved and itcan also be beneficial since induction generators are capable of riding through earthfaults. [Sul 09]

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5.5. Network Reconfiguration

The open loop network configuration is a very common way to operate distributionnetworks. This means that the feeders are actually built in ring structure, but a switch inthe middle of the ring is normally kept open so that the network is actually operated astwo separate radial feeders. Radial way of operating the feeders is often preferredbecause ring and meshed network structures necessitate more CBs and moresophisticated protection. [Lak 95] These kinds of network structure issues were alreadydiscussed in chapter 2.1.1.

Network reconfiguration can be used for many purposes. Maintenance and supplyrestoration tasks are probably the most common utilization purposes for networkreconfiguration but there are also many other things it can be used for. [Col 03] By aproper sequence of switching operations, it is possible to maximize or minimize variouskinds of objective functions. Such objective functions could, for example, deal withlosses, economic and/or reliability indicators, load balancing, fault level minimization,voltage control- or possible multipurpose formulations. The optimization of theobjective functions will also have to take into account possible restrictions such asminimum or maximum node voltages, thermal limits, maximum three phase or earthfault currents, market rules and contracts. Additionally, the optimal configuration couldbe a variable in time. It is, therefore, clear that finding optimums for the kind ofobjective functions is very challenging. Various methods for solving have, nevertheless,been proposed in literature. [Mut 08] Network reconfiguration includes many featuresbut only fault level management will be discussed in this chapter because of itsimportance as one of the key solutions in managing the challenges raised by DG.

5.5.1. Fault level management

Increased fault currents are one of the side-effects of increasing demand in electricity.This is not a new issue at all and methods for limiting the fault currents have beendeveloped since the 1960s. [Put 04] Fault level management has, however, receivedincreased attention due the fact that DG contributes to fault currents. The mostconventional solution to increased fault levels is the replacement of old networkcomponents like CBs whose thermal limits are reached to new ones that have ratings.Replacing network components is, however, often quite costly. [Dti 05]

Another method for reducing the fault currents is the introduction of additionalimpedance in the network. Current limiting reactors are a reasonably cheap way ofaccomplishing this but their utilization unfortunately increases network losses and alsocomplicates the control of voltage profiles. The use of one to one ratio transformers forconnecting large DG units can also be used for increasing the impedance. This methodis most cost-effective when applied already in the design phase. [Dti 05]

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Generators connected through power electronic converters feed considerably smallerfault currents than directly coupled generators as discussed in chapter 3. The problem ofincreasing fault levels can, therefore, also be alleviated by increasing the proportion ofDG units connected through converters. The extra cost of converters would most likelybe offset by their beneficial effect on fault levels. Converters also bring more controlcapabilities to the generators which is important for the development of activedistribution networks. It is anticipated that the growth of fault levels will beconsiderably slowed down because of the increasing use of converters in LV and MVconnected DG units. [Col 03, Dti 05] Fault current limiters (FCL) have the advantage that they do not increase theimpedance and thereby also the losses in normal state like the extra impedancespreviously discussed. [Dti 05] FCLs can be roughly divided into three groups. The firstgroup type FCLs interrupt the fault current instantly, whereas, the second type FCLsonly reduce the fault current to a safe value and leave the actual fault clearance fordownstream relays. The third group is a combination of the two types. This means thatthey first limit the fault current to a safe value and then interrupt it after a preset time. Inpractice the third group type limiters are based on a combination of a type two device inseries with a CB. [Put 04]

Fault limiting fuses and solid-state circuit breaker (SSCB) are examples of firstgroup type FCLs. Fault limiting fuses suffer from the disadvantages that they need to bereplaced after each operation and that it is very difficult to coordinate them withdownstream protective devices. The superconducting fault current limiter (SCFCL) andthe solid-state FCL are examples of group type 2 FCLs. SCFCL has a very lowimpedance during normal operation due the fact the current is flowing through thesuperconducting material. When a fault occurs, however, the impedance of SCFCLrapidly increases because of the transition to normal conducting state. The functioningof solid-state FCLs is pretty similar to the one of SCFCL but it is based on powerelectronics. SCFCL and solid-state FCL are both very promising devices for fault levelmanagement but the high price of SCFCL and the development needs for being afeasible MV-network solution (high losses) in case of solid-state FCL, however, renderboth of these solutions unviable for the use of MV-network fault level management atpresent. [Put 04, Dti 05]

Network reconfiguration can be utilized as a means for mitigating the fault levelproblems either by reducing the parallel feeds in radial networks or by changing thefault current paths. The fault current path can be changed by opening and closing theswitches so that a DG unit is moved electrically further away from the substation andthereby, also the fault current infeed to the substation is reduced. The connection pointof DG units that are connected to a feeder where fault level is a problem can also bechanged to another feeder where fault level is not an issue. Parallel feeder paths in radialnetwork can be reduced by network splitting configurations, which are generallydivided into either operating the bus section CB open or operating a transformer CB inopen standby. [Col 03] According to [Wu 03], network splitting is the most potential

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way of reducing fault currents in the short term because of its relatively low cost, highreliability and flexibility. Reference [Col 03], nevertheless, states that there are alsosome disadvantages related to network splitting as well, as for instance increased losses,harmonic voltage levels, flicker, voltage dips and generally decreased power qualityinvolved. While the increased source impedance caused network splitting is/can bepartially responsible for these problems, one should note that the DG located in thenetwork in question is often the biggest cause for the harmonic voltage levels andflicker. It is also noteworthy that while the power quality behind the one HV / MVtransformer may degrade due to network splitting, the power quality behind the otherHV / MV transformer may at the same time improve since the network with powerquality problems is now isolated from it.

Figure 5.14 illustrates the utilization of network splitting. In the left figure, thesource impedance is increased by operating the network with the bus section CB (EB1)open. This configuration suffers from the disadvantage that the DG unit has to be shutdown during the maintenance of bus 2. In the right figure this problem is avoided bychanging the configuration slightly and adding one new CB (EB2). In thisconfiguration, the DG unit can be switched to feed through bus 1 in (by opening theswitch EB2 and closing the switch EB1) case bus 2 needs to be shut down.

Figure 5.14. Network splitting configurations for the reduction of fault currents [Wu03]

Sequential switching is also one of the strategies that can be used for alleviating faultlevel problem. If the current breaking rating of a CB is exceeded, sequential switchingcan be utilized for reducing the fault current flowing through the overloaded CB.Sequential switching simply means that some of the fault current sources are set to be

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disconnected faster than the problematic CB. [Col 03] Figure 5.15 illustrates thefunctioning of this principle.

Figure 5.15. The idea of sequential switching [Col 03]

Normally, when a fault occurs at the feeder protected by CB 5 in the figure, the faultwould be cleared by CB 5. However, if the fault current contribution from the generatorone in the figure should cause the current breaking rating of CB 5 to be exceeded,sequential switching can be introduced. This means that one or more of the fault currentsources is switched off the grid before the operation of CB5 by opening CB 1, CB2 and/ or CB 6. A failure in sequential switching might, however, cause the current rating ofthe CB whose experienced fault current is meant to be limited to be exceeded whichposes a safety risk for the CB and for people. [Col 03]

Active fault level management is based on active monitoring of the network andcontrol systems. The fault levels are managed by actively reconfiguring the network byturning on temporary impedances and switching controllable loads on and off. Moreflexibility is required from the network as DG units are turned on and off not to mentionthe intermittent nature of many DG units. Active fault management would also utilizeand combine all the conventional fault level management solutions and make themfunction together in a coherent way. Active fault level monitoring and controlcapabilities would be necessary to accomplish advanced active fault level management.[Col 03, Dti 05] Active fault level management would most likely be most efficientwhen implemented in DMS rather than in stand-alone solutions. This sort of effective

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fault level management would necessitate monitoring from multiple locations all overthe supervised network. As additional safety measures the DMS could prohibit thecontrol engineers from carrying out switching operations in areas where fault levels area problem. [Haw 07]

5.6. ANM automation systems

5.6.1. SCADA

SCADA system is used for the supervision and control of distribution networks. Itcommunicates with various network components via RTUs which in turn communicatewith substation automation systems, IEDs and some other components thus providinginformation about the status of the network. SCADA also provides the controllability ofvarious network components such as CBs, remote controlled switches, capacitor banksand voltage regulators to the network operator. [ABB 08b] The system, however, onlyincludes precise information on the substations and their components, whereas, itsinformation concerning the LV and MV networks is only at general level. [Lak 08] Inthe event of a fault or overload at some part of the network an alarm will immediatelybe sent to SCADA so that the control engineer can take appropriate action. The SCADAcan also be preprogrammed to perform certain functions for fastening the restorationprocess. [Lak 95] Figure 5.16 illustrates the distribution system entity. The dashed blueline in the figure represents communication links between the control center systems,RTUs and customer automation, which includes AMR devices and load control. Asillustrated in the figure, SCADA gathers information from various network points likefrom substations and RTUs for control center monitoring and for further analysispurposes carried out by DMS. With the help of RTUs, it is possible to control remotecontrolled disconnectors and obtain data from fault indicators. [Ver 97]

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Figure 5.16. The distribution system entity [Reproduced from Ver 97]

RTUs are playing a major role in obtaining the required network parameters indistribution system. The measurement apparatus like sensors and transducers are usuallydirectly hardwired to RTUs, although the connection to RTU can also be based on acommunication link like LAN. The information is then further transmitted from theRTUs to data concentrators which, in turn, are connected to the SCADA/DMS servers.Generally there are from 8 to 12 RTUs connected to each concentrator which areusually situated at substations. SCADA and DMS are widely used above 11kVnetworks, whereas, the LV networks cannot traditionally be centrally controlled. [Eat06] This might, nevertheless, soon be changed thanks to the rapidly spreading AMRdevices. [Jär 07]

The information about the switching state of the network is critically important.SCADA systems, therefore, include a redundancy computer system so that in a case ofmalfunction in the primary computer the second computer will immediately take controlof the SCADA. The SCADA control computers are also equipped with UPS devicescapable of supplying power to the computers for a long time. [Lak 08] There isadditionally a need to secure the communication arrangements and RTUs.

5.6.2. Distribution Management System

DMS, which is sometimes also referred as NMS (Network Management System) orEMS (Energy Management System), manages the collection, processing and

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presentation of the network data via SCADA and other communicative devices such asRTUs and data concentrators. Present DMSs also utilize many databases such asnetwork connectivity database with real time alarms, trouble call database, plant andcircuit database, work management database, GIS database and customer load database.There are, however, many DMS suppliers and the content of the DMS varies fromsupplier to supplier. Generally, the idea of DMS is to provide real time control of thenetwork to the operator. [Eat 06] The system can, for example, be used for managingthe field crews [ABB 08a], configuration optimization, planning maintenance outagesand calculating fault currents, which can, furthermore, be used for checking the relaycoordination. If any relay coordination violations should come out in the analysis, therelay settings can be reconfigured remotely from the control center. In case of a fault,DMS provides tools such as fault location algorithms and propositions of optimalswitching sequence required for restoring the supply. [Lak 95] The fault locationapplication may, however, also be affected by the fault current contribution of DG. Thisis because the fault location application uses the fault current measured by the IEDs forthe calculation of the fault distance. As discussed in chapter three, IEDs may be blindedbecause of the fault current contribution of DG and thus measure an incorrect faultcurrent value. This naturally leads to an incorrect fault distance calculation. Furtherdevelopment of this application may thus be needed.

DMS performs on-line load flow calculations based on load curves in order toestimate the network bus voltages. The estimation process begins with the estimation ofthe loads. This is accomplished by using customer group specific load curves whichhave their respective temperature correlations. The loads, which are adjusted withoutdoor temperature measurements, and network data, which is obtained from thenetwork information system, are then used as an input to the load flow calculation. Busvoltages and line power flows are given as a result of this calculation. These values arestill relatively inaccurate and, therefore, the feeder loads are readjusted based on thereal-time measurements from the substation. The load flow is then recalculated with thereadjusted load values in order to obtain better results. The real-time measurementsmainly consist of measurements from the voltages at the substation busbar and from thecurrents of each feeder. With such a few number of real-time measurements it ispossible to obtain accurate feeder specific load distribution but the load distributioninside the feeders remains uncertain. The line current and voltage level estimates insidethe feeder will then as well be inaccurate. This is problematic since accurate stateestimation forms the basis for the active network management as well as for manytraditional distribution automation functions. The accuracy of the estimate could beimproved by increasing the number of real-time measurements. This is unfortunatelyrestricted by the expensiveness of measurement equipment in medium voltagenetworks. The number of real-time measurements could, however, also be increased byutilizing the AMR devices which many network companies have already installed invast numbers. In order to obtain the maximum benefit of measurements provided by theAMR devices, certain improvements in the state estimation algorithms would,

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nevertheless, be necessary. Some of these kinds of improvements are presented in [Mut08]. [Mut 08]

The SCADA/DMS combination could also make use of specific data provided bythe AMR system and thereby extend the network management to low voltage level. TheAMR devices provide information that could be used for fault indication, fordetermining the fault location and the isolation of the faulted part of the network. Thiscould remarkably improve the reliability of the supply since traditionally the faultindication and location in the low voltage networks has been based on customer troublecalls. The AMR system can also enable the monitoring of the power quality and providevaluable interruption data for further analysis and other purposes. [Jär 07]

The thermal ratings of conductors and other network components can sometimeslimit the allowable transfer of electricity. On overhead lines, the allowable transfer istraditionally determined by some fixed or seasonal ratings of each conductor type. Inpractice, however, the thermal limits of overhead lines are not constant all the time butthey are actually dependent on ambient conditions like windiness and temperature. Byutilizing real-time measurements of loading and ambient conditions, one can estimatethe true thermal limits and often allow a greater transfer of electricity based on thisestimate. This may naturally sometimes enable a greater amount DG to be connectedparticularly since the electricity production of some renewable energy sources like windpower correlates well with windiness. The dynamic line rating application has alreadybeen added to some DMSs. [Mac 07]

5.7. Examples and demos of active distribution networks

5.7.1. The Orkney Islands demo

There have already been some real life demos of active network management. One ofsuch demos has been carried out in the Orkney Islands. The distribution network ofOrkney Islands consists of overhead lines and submarine cables interconnecting themultiple islands. There is also a connection to the mainland which is established via twosubmarine cables whose combined import/export capacity is roughly 40MW. Thedemand of electricity on the area varies from 8 MW to 32 MW. Orkney Islands are richin renewable energy and there is already 26 MW of FG and 21 MW of NFG that arebased on a mixture of wind power, marine energy and gas generation. As alreadydiscussed in chapter 5.4.2, the FG units have primary access during normal operatingconditions as well as during N-1 contingencies. In this particular case, the loss of theother submarine cable connection to mainland represents the N-1 contingency. TheNFG units can operate freely during normal operating conditions but are subject totrimming or tripping during N-1 contingencies. [Cur 07b]

The extra generation capacity that can still be allowed because of the variations indemand and FG & NFG generation is called the RNFG as already discussed in chapter

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5.4.2. The main limitation for the allowable generation in the Orkney network is thethermal limits of the utilized conductors. Overvoltages do not cause limitations for thegeneration since a dynamic reactive power compensation device and multiple shuntreactors have already been installed for alleviating voltage problems. [Cur 07b] Figure5.17 illustrates the functioning of the active power flow management (APFM) schemethat was used in the demo. The idea in the APFM is to divide the network into smallerzones and to control the power flows between the zones. In the flow chart of figure5.17, another name for RNFG, namely the term New Non-Firm Generation (NNFG), isused.

Figure 5.17. Flow chart of the active power flow management scheme used in theOrkney demo [Cur 07b]

As it can be seen from the flow chart, the RNFG units in a zone are first trimmed(regulated down) if the export from the zone in question exceeds the predefinedthreshold and, finally tripped if trimming is not sufficient. The curtailing of the RNFGunits can be executed according to a last-in-last-out (LIFO) basis for fairness’ sake.Because of the real time power flow measurements used in the Orkney demo, theallowable RNFG capacity could be estimated in real time. In the demo, this APFMscheme was used for controlling a wind farm with the help of two programmable logic

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controllers (PLC). The other PLC was controlling the per unit output power of the windfarm, whereas, the other PLC (central PLC) was used for monitoring the currents at acritical point in the Orkney distribution network. The central PLC sent set point ordersto the PLC controlling the wind farm whenever the currents breached the trim margin.The results of the demo can be seen from figure 5.18. The arrows in the figure indicatethe moment at which a new set point was issued, whereas, the curve shows the per unitpower output of the controlled wind farm. [Cur 07b]

Figure 5.18. The per unit power output of the wind farm controlled in the OrkneyIslands demo [Cur 07b]

5.7.2. The demos in the ADINE project

An active voltage control scheme has been developed in the ADINE project and itsfunctionality will be tested in a real life demo. In this demo, a coordinated voltagecontrol scheme will be issuing instructions to a DG sized hydro power plant and to anOLTC of a HV / MV transformer. The scheme has already been successfully tested in areal time simulation environment. Real time simulation studies exploring thefunctioning of real commercial IEDs in the presence of DG are also performed in theADINE project. In these tests, various protection schemes like conventional overcurrentprotection but also some new MV network protection solutions like distance and linedifferential IEDs will be examined. A communication based LOM protection method(based on GOOSE messages and binary transfer signals) is also studied in the RTDS

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environment. The ADINE project also includes a demo, where a microturbine is usedfor eliminating voltage variations in LV network. In this demo, voltage variations arecaused by disturbances in both LV and MV networks. A new generation STATCOMcapable of eliminating power quality problems like flicker and harmonics is alsodeveloped for MV network in the project. ADINE project will additionally develop newtools for active distribution networks like the new fault location solutions and aprototype implementation of the protection setting planning tool that was alreadypresented in chapter 4.1.3.

5.7.3. The fault location application

The fault location application in the DMS is no longer a demo but has been successfullyin real use for years. Together with other distribution automation like remote controlleddisconnectors and microprocessor based relays, the fault location application cansignificantly fasten the supply restoration after faults. This can be clearly seen fromfigure 5.19 which represents the mean outage duration of a customer per fault in thedistribution network of a Finnish network utility, Koilis-Satakunnan Sähkö Ltd.

Figure 5.19. The mean outage time of a customer per fault in the distribution network ofKoilis-Satakunta Ltd

In the end of the 1980’es, Koilis-Satakunnan Sähkö invested in remote controlleddisconnectors, equipped all the MV feeders with microprocessor relays by spring 1991and introduced the first fault location application in the beginning of 1991. Since 1991all the three have been in everyday use and the result is clear. The average outageduration per fault shortened radically as figure 5.19 shows. The accuracy of this faultlocation application is in practice some hundred meters. [Jär 95] As already noted, thisapplication may need some improvements in order to take DG into account.

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5.8. The commercial issues of ANM

Chapter five has pointed out that ANM can greatly increase the amount of allowableDG in distribution networks with minimum or no primary network reinforcements at all.The adoption of ANM does, of course, require some investments but the benefitsachieved with the help of ANM are likely to clearly overweight the costs. In this sense,the utilization of ANM should, in principle, be attractive. However, there are generallyno incentives for the network companies for offering ANM services at the moment as asolution for the connection a larger DG capacity. This kind of framework gives nomotivation for the network companies to take ANM into use. In fact, since networkutilities are doing business in a regulated monopoly environment where their allowedrevenues are regulated in relation to the supply quality they provide and to the networkreinforcement investments, it is actually more favorable for the utilities to invest innetwork infrastructure rather than use ANM. It is thus evident that some kind ofsupport scheme needs to be put into practice in order to motivate the network companiesfor the adoption of ANM. According to [Pec 07], there are roughly three approaches forsuch support scheme.

The idea of the first approach is to increase the recoverable expenses caused byANM, in other words, changing the limits set by the price control regulation. Theincreased capital and operating expenses could be recovered by increasing the networkfees of the connected generators benefiting from the ANM service and/or demandcustomers. The idea of the second approach is to establish an incentive scheme thatencourages the DNOs to connect more DG. This could also be funded by increasing thenetwork fees for generators and/or demand customers. In the third approach, a marketmechanism outside of the regulatory framework would be established. The DNOs couldoffer the ANM service to generators in this marketplace, who respectively were tobenefit from the service in the form of increased energy sales. When applying thisapproach, there would naturally be potential for ANM service contracts whenevermutual benefit for the DNO and for the generator was present. [Pec 07]

5.9. The transition towards ANM

The existing distribution networks vary from country to country and it is likely that thiswill also be the case with the future network infrastructure as well. The exact definitionof active distribution networks will thus probably also vary to some extent from party toparty. The attributes that have been presented in this chapter are selected from manydifferent publications and reports and it is likely that not all of these attributes areapplied in every region. The speed of the transition towards ANM is probably ofsomewhat dependent on the growth speed of DG since the facilitation of the connection

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of DG is the main idea behind ANM. Naturally, as already discussed, the change alsonecessitates an appropriate commercial framework that encourages the DNOs to adoptANM.

The change from passive to active network management will not happen overnightbecause of the extensiveness of the existing distribution networks in the developedcountries. The change will rather take place in suitable steps as it seems to be happeningin the UK, where the active control installations have so far been mostly stand-aloneunits controlling a single DG unit connected to a single feeder. While planning thesekinds of stand-alone installations designed for the optimization of the existing network,one should also consider the future requirements for the active network. [Rob 04] Largeamounts of stand-alone installations that do not take into account the prospective needswill probably lead to distributed local control of various components. This might workwell for long but coordinated control centre based management strategy may, at somepoint, be desirable for further optimization of network operation. The distribution oflogic around the network, nevertheless, increases the reliability of the system in thesense that the seriousness of malfunction in the communication system is reduced [Rob04].

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6. THE SIMULATION ENVIRONMENT AND THESIMULATION MODELS

The real-time-digital-simulator (RTDS®) was used for performing the simulation studiesof this thesis. RTDS performs the network calculations and communications betweenexternal devices in real time which enables the interaction studies of real physicaldevices and modeled power systems. One RTDS module consists of a rack whichcontains a number of various kinds of processor cards, communication cards andchannels and a power supply unit. The idea in the real time simulations of this thesiswas to test the functioning of real commercial IEDs in the presence of DG and examinewhether the protection is or is not affected by DG.

The graphical user interface to RTDS modules is provided by a dedicated softwaresuite called RS-CAD. This CAD-program is installed to a PC workstation which isconnected to the RTDS rack through an Ethernet cable. The RS-CAD software suitecontains a Draft program for the actual modeling of the power system, a Runtimeprogram for the control of the modeled power system, a T-line program for modelingtransmission lines, a Cable program for modeling cables and a Multiplot program foranalyzing the simulation results. Power systems are first modeled in the Draft programwith the help of power- and control system libraries included in the program. Once themodel is ready, it is first compiled in the Draft mode after which it can be controlled inthe Runtime mode. The runtime mode can be manually controlled or alternativelyautomatically controlled by using predefined control-blocks and scripts. [Mäk 07a,RTD 07]

The simulation environment used in the simulation cases of this thesis is presentedin figure 6.1. Different types of RTDS racks are shown at the upper left corner, but onlyone medium sized rack was used in these simulation studies. One rack is capable ofrunning a simulation model with 54 electrical nodes maximum. If a larger model isdesired, the modeled power system can be divided into parts which will be distributedinto multiple racks. The RTDS racks are controlled by a PC workstation which is alsodepicted in the middle of the figure. As already mentioned, real physical devices likeprotective relays can be connected to the RTDS and placed into any location in thepower system model by utilizing appropriate connections. The simulation studiespresented in this thesis are concerning the functioning of real IEDs in the presence ofDG. At the upper right corner, the two commercial IEDs manufactured by the ABB thatwere used in the simulation studies, are shown. The amplifier, which is located at thelower right corner, was used for amplifying the output signals coming from the RTDSto an appropriate range for the IEDs. The amplifier is required because the digital-to-

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analogue converter (DDAC) card, which provides twelve analogue output signals fromthe RTDS, is only able to supply signals in the range of -10 V to +10 V [RTD 07]. Thecommunication between the IEDs and the RTDS rack (the control commands to theCBs in the modeled network) was established by connecting certain output ports of thebackplanes of the IEDs to the DOPTO (digital optical isolation system) card mounted inthe RTDS rack. The DOPTO card, which provides 24 digital inputs/outputs, is meantfor connecting external devices to the RTDS.

Figure 6.1. The real time simulation environment

All the simulation cases presented in this thesis were carried out using one RTDS rack.The utilized rack contains one workstation interface card (WIC card), one (RPC) andeight 3PC processor cards. Each rack must be equipped with one WIC card (WIF cardin newer installations) which takes care of the synchronization between multiple racks,rack diagnostics, backplane communications and communication between RTDS andthe PC used for controlling RTDS. The RPC card, which contains two RISC IBMPPX750CXe power PC processors, is mainly dedicated for solving the networkequations. It supports network solutions up to 54 electrical nodes (18 three phasenodes). 3PC cards are used for solving the equations related to control and powersystem models in the RS-CAD model. The number of 3PC cards, each of whichcontains three ADSP-21062 SHARC processors, can vary from installation toinstallation. The number of these 3PC cards determines the amount of the power- andcontrol system components that can be run in real time. [RTD 07]

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6.1. The distribution network model

A network model representing a real Finnish distribution network was composed forthese simulations studies. Because of the limited number of electrical nodes provided byone RTDS rack, the network model had to be strongly simplified. While carrying outthis node reduction task, the objective was to maintain the voltage profiles of the twofeeders included in the model as close to the original profiles as possible. The shortcircuit current values were also maintained close to the original ones. This networkmodel is shown in figure 6.2.

Figure 6.2. The distribution network model used in many RTDS tests

The rectangles marked with the sign PI are nominal - line representations which areavailable in the RS-CAD component libraries (If_rtds_sharc_sld_PI3). Combinedcustomer loads are marked with arrows in the figure. They were modelled in such a waythat the type of the loads was changeable in the RS-CAD runtime mode. This meansthat the load types could be changed to constant power, constant current or constantimpedance mode from simulation to simulation. The circle marked with a G letterrepresents a hydroelectric power plant, which runs a synchronous generator with arating of 1,6 MVA. Although the power plant is situated at the end of the other feeder inthe figure, it is actually placed into various locations from simulation to simulation forstudying different kinds of impacts of DG. The crosses represent CBs(if_rtds_sharc_sld_BREAKER from the RS-CAD power system components library)which can be set to be controlled by real IEDs or alternatively manually controlled. Thenetwork model is normally operated in radial mode, but by closing the switchconnecting the two feeders (marked by horizontally directed adjacent lines) the model

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can also be operated in ring mode as well. The electrical parameters of the PI-sectionsrepresenting the lines are shown in table 6.1, whereas, the real and reactive power of theloads are marked in table 6.2.

Table 6.1.The electrical parameters of the two feedersNodes Parameters in per unit (100 MVA, 20 kV base)

From To R X B R0 X0 B0Substation Killi_1 0.1254 0.1343 5.53E-05 0.1941 0.8397 3.54E-05

Killi_1 Killi_2 1.0996 1.111 1.57E-04 1.569 5.6483 9.56E-05Killi_2 Killi_3 0.1982 0.2082 2.96E-05 0.2865 1.0589 1.80E-05Killi_3 Killi_4 0.0958 0.0902 5.15E-05 0.174 0.443 4.67E-05

substation Ritari_1 0.834 0.8172 1.59E-04 1.1986 4.4448 9.04E-05Ritari_1 Ritari_2 1.3275 0.8708 1.17E-04 1.6818 4.3592 7.26E-05Ritari_2 Ritari_3 1.8759 0.6277 7.50E-05 2.113 3.0243 4.89E-05Ritari_3 Ritari_4 2.6216 0.9253 1.11E-04 2.9722 4.4725 7.24E-05

Table 6.2.The real and reactive power consumption of the loadsNode Killi_1 Killi_2 Killi_3 Ritari_1 Ritari_2 Ritari_3 Ritari_4

P [kW] 680.3 115 59.5 306.3 493.1 193.8 111.6Q [kVAr] 188.8 32.7 16.7 87.7 140.7 55.2 31.7

A 16 MVA star-star connected transformer was used as the HV/MV transformer. Thewinding ratio in the If_rtds_sharc_sld_TRF3P2W transformer model (RTDS powersystem library) was 110 / 21 kV. The transformer model includes a tap changer which ismanually controllable by the user.

6.2. The generator models

Two different generator models were used in the simulation studies of this thesis. Thefirst model is a 1,6 MVA rated synchronous generator powered by a hydro turbine,whereas, the second model is a roughly 10 MVA rated synchronous generator run by adiesel engine. Both of the machines were modelled using the synchronous machine(RTDS_SHARC_MAC_V3) model from the RS-CAD power system componentlibraries. This generator model component also includes a transformer. The controlsystems of the generators were modeled using various components from the RS-CADcontrol system libraries.

6.2.1. The brushless excitation system

A brushless excitation system was used in both of the utilized synchronous machinemodels. The magnetizing current in synchronous generators with brushless excitation

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systems is produced with the help of a small synchronous generator whose armaturewinding is rotating on the same shaft with the main generator and whose excitationwinding is stationary. The magnetizing current produced by the smaller machine isrectified with the help of a rotating diode rectifier and fed to the excitation winding ofthe main generator. The amplitude of this magnetizing current can be controlled byregulating the magnetizing current that is fed to the smaller generator. [Par 06b] Figure6.3 represents the basic structure of the brushless excitation system that was utilized forproducing the field current to the generator. The system consists of an exciter model andan automatic voltage regulator (AVR). [Tut 08b].

Figure 6.3. The basic structure of the brushless excitation system of the machine [Tut08b]

The block diagram of the exciter, which is depicted in figure 6.4, is similar to those ofthe IEEE AC5A and IEEE AC8B excitation system models. VR in the figure stands forthe output of voltage regulator and exciter field voltage, TE for the exciter time constant,SE for a nonlinear saturation function, KE for a constant and Efd for the main generatorfield voltage. [IEE 06, Tut 08b].

Figure 6.4. The utilized exciter model [Tut 08b]

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Chapters 6.3.2 and 6.3.3 briefly present the structures of the synchronous generatormodels that were utilized in the simulation studies of this thesis. More precisedescription of these models can be found from the references [Par 06a, Par06b and Tut08b].

6.2.2. Hydroelectric power plant model

The first generator model that was used in these studies is a representation of ahydroelectric power plant using a salient pole synchronous generator manufactured byStrömberg Inc. (nowadays part of the ABB Corporation). The rated power, voltage andfrequency of the machine are 1600 kVA, 660 V and 50 Hz. A delta-star transformerusing a 21 kV / 0.660 kV tap ratio was used for connecting the generator in the network.The general structure of the machine model will be presented here, whereas, the detailedelectrical parameters are given in [Tut 08b].

It is assumed in these simulations that the generator is not being used for frequencycontrol, which often is the case with DG units. The torque of the generation unit is,therefore, simply a user definable constant. Another simplification of the power plantmodel is that the turbine controller is not modeled. This is justified because hydropower plants have relatively high inertial mass which makes them respond quite slowlyto changes, whereas, the protection studies of this thesis are only focused on very shorttime scales. The turbine controller would, therefore, hardly have had any effect on thesimulation studies of this thesis.

The field voltage of the exciter (VR in figure 6.4) is determined by the AVR whichis shown in figure 6.5. The type of the AVR is Strömberg SMUX 3R1. It contains aload compensator, field current- and minimum frequency limiters, a PID controller anda controllable thyristor rectifier. It was assumed that the exciter can always produce thecurrent determined by the AVR. Field forcing circuitry was, therefore, not modeled.[Tut 08b]

Figure 6.5. The structure of the AVR [Tut 08b]

The field current- and the minimum frequency limiters were not modelled because therewas no available data available for modelling them properly. This, fortunately, was nota problem from the frequency limiter point of view because its threshold frequencywould have been 45 Hz (for 50 Hz systems) and the generator protection was set to tripat 47 Hz [Tut 08b]. It is, however, recommended that field current limiters should be

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modelled for simulation studies where certain conditions such as islanding cause themachine to operate at high levels of excitation for a sustained period [IEE 06]. It would,thus, have been advisable to model the field current limiter for the islanding studies.However, the absence of the field current limiters actually makes the detection of anislanded zone more difficult to LOM protection because the reactive power controlcapability of the generator is not limited by the field current limiters. This means thatthe results of the LOM tests of this thesis are rather conservative. The characteristics forthe field current limiter are listed in table 6.3.

Table 6.3.The characteristics of the field current limiter [Tut 08b]

The load compensator and terminal voltage transducer model is depicted in figure 6.6.The output of this block diagram, namely the measured value of the terminal voltage(VC in the figure), is meant to be used as an input to the AVR [IEE 06]. This blockdiagram was, however, not modeled to the RS-CAD environment because of theirrelevance of this component for the studies of this thesis. This simply means that theload compensation parameters (RC and XC in the figure) as well as the time constant (TR

in the figure) were thought to be equal to zero.

Figure 6.6. The block diagram of the load compensator and the terminal voltagetransducer [IEE 06]

The synchronous machine (RTDS_SHARC_MAC_V3) model from the RS-CAD powersystem component libraries was used for representing the machine. This componentincludes a transformer. The AC8B excitation system model was not available in the RS-CAD component libraries and it, therefore, had to be modeled by using simple logiccomponents.

6.2.3. The reactive power control of the hydro power plant

The reactive power control of the generator is established by controlling the set point ofthe AVR (cascade control). The reactive power controller is a continuous PID controllerwhich tries to maintain the reactive power at its set value. The block diagram of thereactive power controller is shown in figure 6.7.

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Figure 6.7. The block diagram of the reactive power controller [Tut 08b]

This controller is similar to the IEEE Var Controller Type 2 with the only exception thatthe IEEE controller uses PI controller, whereas, the utilized one uses PID controller.The reference reactive power setting of the controller is calculated from equation 6.1.[Tut 08b]

ref

refmeasuredrefmeasuredref PPQ

coscos1

tan2

(6.1)

Pmeasured in the equation refers to the measured power, whereas, cos( ref) refers to thereference power factor. This type of reactive power control was used in the protectionsensitivity and selectivity studies, whereas, for the LOM protection studies this controlwas simplified. The simplification was such that the reactive power reference settingwas made simply user definable. This was done because it made the determination ofthe shape of NDZ considerably more straightforward since all possible combinations ofactive and reactive power generation set points could then simply be given by the useror by the control script.

6.2.4. Diesel engine model

The diesel engine model, which was also used in the simulation studies of this thesis, isa representation of an AMG series salient pole synchronous generator by ABB. Itsnominal voltage and power are roughly 13.8 kV and 10 MVA respectively. A 16 MVArated transformer using a 20.4 kV / 13.8 kV tap ratio was used for connecting thegenerator in the network. The general structure of the model is presented in this chapter,whereas, a more detailed representation can be found from [Par 06a].

The diesel engine model was used only for the protection sensitivity and selectivitystudies. In the original model, there was no possibility for the user to adjust the powerfactor or reactive power. The model was, therefore, slightly simplified in such a way

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that the reactive power output of the machine could be controlled. This wasaccomplished in such a fashion that the excitation system of the generator model wasbypassed and the field voltage fed to the main generator (Efd) was changed to be userdefinable. The field voltage setting in the simplified model is determined by altering aslider named “Uctrl”. This simplification does slightly alter the fault current fed by thegenerator but not remarkably. The effect of the simplification on the fault current fed bythe machine can be seen from figure 6.8 where the fault current fed by the originalmodel is depicted on the left and the respective current fed by the simplified model isdepicted on the right. The simulated fault was set last for 0.25 seconds in the RS-CADruntime. The odd looking ball-shaped current pulse following the actual fault situation,which is caused by the dynamical behavior of the synchronous machine, is not ofparticular interest from the overcurrent protection point of view because the trippingtimes of the IEDs were 0,08 seconds for the low stage and 0,22 seconds for the highstage protection.

Figure 6.8. The simulated short circuit current when the 10MVA machine is connectedto node Killi 1 and a three phase short circuit occurs at node Killi 2. The excitationsystem is being used in the left figure, whereas, in the right figure the field voltage of themachine is manually controlled.

The speed control model of the generator has four main sections as illustrated in figure6.9. These are the filter, the speed controller, the actuator and the engine. The modelalso includes an oscillation component that oscillates sinusoidally at 5 Hz frequency andwhose magnitude is 0.5 % of the nominal power. The magnitude of the oscillationcomponent does not significantly change when the power output of the generator ischanged. [Par 06b]

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Figure 6.9. The structure of the speed control and the gas turbine model [Par 06b]

The speed controller section is a PID controller which acts in droop control mode. Thismeans that the output power of the generator is inversely proportional to the speed ofthe machine. The machine produces the set value when it is running at its nominalspeed. The speed setting ( set) is calculated from the equation 6.2. [Par 06b]

DPP measuredsetset )(1 (6.2)

The notation Pset in the equation signifies the set value of the output power, the notationPmeasured stands for the measured power and the notation D stands for the regulatingpower of the generator. [Par 06b] The transformer connecting the generator to the MVnetworks is included in the RS-CAD synchronous machine modelRTDS_SHARC_MAC_V3 that was utilized. The detailed parameters of the transformercan be found from the reference [Par 06a].

6.4. The load models

Exponential static load models were utilized in these simulations. This wasaccomplished in the RS-CAD draft mode by using the dynamic load model(rtds_udc_DYLOAD) components combined with exponential coefficient LoadCalculation blocks (rtds_ctrl_sharc_ECL). The way these loads behave can be seenfrom equations 6.3 and 6.4. The terms V0 and f0 are the nominal voltage and frequency,whereas, the exponents nP and nQ determine how much the voltage at the connectionpoint of the load affects the consumption of the loads. The terms KPf and KQf

respectively determine how frequency dependent the real and reactive powerconsumptions are. In these simulations, however, KPf and KQf were set to zero since nofrequency dependency was desired. [RTD 07]

00

0.1 ffKVVPP Pf

nP

Ord (6.3)

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00

0.1 ffKVVQQ Qf

nQ

Ord (6.4)

When nP and nQ equal to zero (constant power load), there is no voltage dependence atall. Respectively, when these exponents equal to one, the load is called constant currentload, whereas, for constant impedance loads the exponents are set to two. The real- andreactive power of the loads are initially set equal to the user defined terms POrd and QOrd.

The dynamic load model also includes a variable Vmin which determines the voltagelevel below which the consumption of the load collapses. [IEE 93, RTD 07] Figure 6.10shows the interdependence between the consumption of the loads and the voltages in theLOM simulation model. The behavior of constant power, constant current and constantimpedance type loads are drawn in the figure.

Figure 6.10. The interrelation between voltage and the power consumed by varioustypes of loads.

It can be seen from this figure that the loads behave according to the defined exponentswhen the voltage is above 0.5 times the nominal voltage but collapses below this limit.This user definable collapse point (Vmin in the rtds_udc_DYLOAD component) is,nevertheless, never reached in the simulation studies of this thesis since the voltage doesnot fall below 14 kV (which corresponds to 0.67 times the nominal voltage) in any ofthe examined cases.

0.5xUn

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6.5. The utilized IEDs and the amplifier

Two different IEDs were used in the simulation studies. Both of the IEDs arecommercial products by ABB. The older IED model, namely the REF543, is originallymeant to be used for feeder protection but it was configured to function as generatorLOM protection for the simulation studies of this thesis. The LOM protectionconfiguration of the REF543 IED was created with the help of a dedicated programcalled CAP505. With the help of this program, the user can also remotely read andchange the protection settings of the IED. The protection functions that were configuredto the LOM IED (REF543) were over- and under frequency protection, over- and undervoltage functions, as well as, ROCOF. More information concerning this IED can, forexample, be found from [ABB 09a]. Figure 6.11 shows the appearance of these twoIEDs.

Figure 6.11. The REF543 and REF615 IEDs by ABB

The newer IED, namely the REF615, was used for feeder protection in these simulationstudies. The REF615 utilized in these studies was based on non-directional overcurrentprotection. The managing of the protection settings was carried out with the help of thePCM600- protection and control manager program. More information concerning thisIED can, for example, be found from [ABB 09b]. The connection diagrams of theseIEDs can be found from appendix 3 and appendix 4.

An Omicron CMS 156 amplifier was used for raising the voltages and currents to arealistic scale for the use of the IEDs. The voltage amplification ratio in the CMS 156 is50 V to 1 V, whereas, the current amplification ratio of this device is 5 A to 1 V. Thismeans that not only the voltage output of the amplifier but also the current output of theamplifier is controlled by a voltage input signal. The maximum three phase AC outputvoltage of CMS 156 is 3 x 250 V, whereas, the maximum output current is 3 x 25 A.More details can be found from [Omi 09].

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7. SIMULATION RESULTS AND ANALYSIS

This chapter presents the two simulation study cases that were performed as a part ofthis thesis. The first case examines protection sensitivity and selectivity issues in thenetwork model whose details were presented in the previous chapter. The nondirectional overcurrent IED which was also presented in the previous chapter was usedfor controlling the circuit breakers of the network model in this study case. The secondsimulation study deals with the NDZ problem of LOM protection. The same networkmodel was also used for this study. The theory behind these phenomena is presented inchapters two and three.

7.1. Sensitivity and selectivity of an overcurrent relay

The idea behind these simulation studies was to find out how a REF615 non-directionalovercurrent IED would manage to protect a network including DG. The network modelused in these studies was presented in chapter six. The location of the generator wasvaried between various networks nodes while for each generator location three phaseshort circuits were inflicted in the simulations in order to find out possible problems inprotection sensitivity or selectivity. Both feeders had four different locations (electricalnodes) for the DG unit and five locations for the faults. The hydroelectric power plantusing a 1,6 MVA rated synchronous generator (presented in the previous chapter) wasfirst used for the studies. The simulations, however, indicated that no particularprotection problems occurred when this DG unit was used. The simulations were,therefore, repeated using the 10MVA rated synchronous generator powered by a dieselengine (also presented in the previous chapter).

7.1.1. Sensitivity tests

A feeder relay has to detect all faults in the line under its supervision reliably. On theother hand, a feeder relay should not trip when there is no need for it. This means thatthe tripping current threshold of a feeder relay has to be lower than the magnitude of thesmallest fault current but higher than the highest current magnitude that can occur undernormal circumstances. The lowest fault current value on a feeder is determined by a twophase short circuit at the end of the feeder in question, whereas, the maximum demandsituation determines the highest current under normal circumstances. This means thatthe tripping current setting has to be somewhere between these two. A need to change

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the protection settings, however, often arises when a generator is connected to thefeeder. In the following it will be examined whether there is a need to alter theprotection settings when two types of DG units are connected to the modeled networkshown in figure 6.2.

The functioning of a REF615 overcurrent IED for the protection of feeder Killi infigure 6.2 was first studied. A two phase short circuit at the end of feeder Killi wassimulated with the RTDS in order to select appropriate protection settings. It was foundout that the minimum fault current Ik2min in this case was 1220 A. The maximum loadcurrent under normal circumstances in the feeder Killi, on the other hand, was 23.05 A.The low stage current limit was, therefore, set to 4 times the nominal current of the IEDwhich corresponds to 400 A. In this case, the protection settings could be easilydetermined because the margin between the Ik2min and maximum load current was solarge. The protection settings chosen for this case are shown in table 7.1. The idea inthese protection sensitivity tests was, however, mainly to find out if the low-stageovercurrent protection would fail to operate in any situation. This is because the failureof the low-stage limit would actually prevent the IED from protecting the feeder, whichis the most onerous case. The protection was functioning well with these settings whenthere was no generation connected to the network.

Table 7.1.The settings used for the REF615 IED for the protection of feeder KilliCurrentlimit Operation time

Minimum fault current Îk2min 1220ANominal current (In) of the IED 100ALow stage current limit 4 x In 0.22sHigh stage current limit 20 x In 0.08sInstantaneous stage current limit 40 x In -Other functions disabledMax load current 23.05 A

The 1.6 MVA rated synchronous generator was now connected to various locationsalong the feeder Killi (at nodes Killi 1-4). It was set to produce 1,289 MW by setting themechanical torque to 0.96 and the power factor to 1.0. This case study showed that theprotection was functioning properly also when the DG unit was connected. The IEDwas tripped by the high stage current limit when the fault occurred directly at the CBterminals as well as in the case when the fault occurred after the first PI section (NodeKilli 1). In case of the three furthest locations (Nodes Killi 2-4) the IED was tripped bythe low stage limit.

The same tests were repeated for the other feeder Ritari which is electrically weakercompared to feeder Killi. The DG unit was now placed to various locations along feederRitari (at nodes Ritari 1-4). The protection settings of the IED were kept the samealthough, in reality, the settings would very likely have been changed because the

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minimum fault current (îk2min) of this feeder without any generation connected was490 A. It was, however, found out that no sensitivity problems occurred even though thelow-stage limit was this high. Protection sensitivity problems would have been evenmore unlikely if the low-stage setting would have been lower. The effect of thegeneration unit can, nevertheless, be clearly seen by comparing the two plots of figure7.1. The left figure represents the situation where a three phase short circuit occurs atthe end of feeder Ritari when there is no generation is connected, whereas, in the rightfigure the DG unit is connected to the node Ritari 1. The comparison between these twofigures clearly shows that the generator reduces the current seen by the feeder IED.

Figure 7.1. The effect of the generation unit on the fault current magnitudes

7.1.2. Selectivity tests

The effect of the generation unit on protection selectivity was studied next. The1.6 MVA DG unit was connected to feeder Ritari, whereas, the faults locations were onthe other feeder. Because there was no actual protection on feeder Killi in this case, thefault duration times were used for “modeling” the operation times of the protection ofthis feeder. The fault duration time was first set to 0.25 seconds because the operationtime for the low-stage overcurrent limit of the IED was 0.22 seconds. This fault durationtime, in a way, is the worst case from the protection selectivity point of view because itcan unintentionally cause the low-stage-limit of the IED to trip. The idea was to find outwhether this fault duration time should cause any problems and in case if it did, shorterduration times were to be tried out. The low stage setting was set to 150 A in this case.

It was found out that no selectivity problems occurred when the generator wasconnected to the three furthest nodes of the feeder (at nodes Ritari 2-4). However, anunintentional tripping occurred when the generator was connected to node Ritari 1 and athree phase short circuit lasting for 0.25 seconds was inflicted at the terminals of the CBthat was protecting feeder Killi. A fault occurring at the CB terminals would,nevertheless, most likely be cleared by the high-stage (or even instantaneous) protection

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which would reduce the fault duration to 0.08 seconds. A fault this short would nolonger cause any selectivity problems. The situation was found similar when thegenerator was connected to the CB terminals of feeder Ritari.

7.1.3. Selectivity tests when using a 10 MVA synchronous generator

No particular protection problems occurred because of the 1.6 MVA synchronousgenerator when suitable protection settings were utilized. Similar kinds of sensitivityand selectivity tests were, therefore, performed using the roughly 10 MVA rated dieselengine powered synchronous generator. This generation unit was adjusted in such a waythat it produced 4.23 MW with a power factor close to unity when it was connected tothe node Killi 1. This was achieved by setting the following settings:

Wref = 1.0203Uctrl = 1.226

The generator, however, began to produce more reactive power as its location wasmoved further towards the end of the feeder. After stabilizing, the generator produced4.07 MW while consuming 0.37 Mvar on average when it was connected to the end offeeder Killi (Node Killi 4). The size of this generation unit would perhaps have beenunreasonably great for this kind of network especially if no active voltage controlmethods were utilized. This was clearly visible from the increased voltages in theneighborhood of the generator. The purpose of this study was, however, only toexamine the functioning of the protection and not voltage levels.

The connection point of the generator was first altered between various locationsalong feeder Killi, whereas, faults were inflicted on feeder Ritari. The low-stage settingof the IED was set to 200 A while leaving the other settings untouched. When thegeneration unit was connected to the three furthest nodes of feeder Killi (Nodes Killi 2-4), only 0.20 second and 0.25 seconds lasting faults at the node Ritari 1 caused the IEDprotecting feeder Killi to trip. 0.08 seconds lasting faults on the same point, however,did not cause the IED to trip. As already discussed, faults occurring this close tosubstation would most likely have been cleared by the high stage overcurrent protectionof the IED protecting feeder Ritari and no selectivity problems had probably, therefore,occurred in this case. Faults occurring further along feeder Ritari caused no problems atall. The generation unit was now connected to the first two nodes of feeder Killi (at theCB terminals and at node Killi 1) for finding whether this would cause any problems. Itwas found out that still no selectivity problems aroused when faults occurred at the twofurthest nodes of feeder Ritari (nodes Ritari 3-4). However, 0.20 seconds and0.25 seconds lasting faults at nodes Ritari 1-2 caused the IED protecting feeder Killi totrip. This indicated that there was already a certain risk of unwanted tripping. It was,nevertheless, also noted that 0.08 seconds lasting faults on the same point did not causethe IED to trip.

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The form of the fault currents seen by the two CBs are shown in figure 7.2 when athree phase short circuit occurs at node Ritari 2. The left figure represents the faultcurrent seen by the CB protecting feeder Killi, whereas, the right figure respectivelyrepresents the fault current seen by the CB protecting feeder Ritari. Note the differentscaling in these two figures. The strange form of the fault current in the left figure iscaused by the dynamic behavior of the synchronous generator.

Figure 7.2. The fault current seen by the two feeder IEDs when a three phase faultoccurs at the node Ritari 2

It was, however, found out that the selectivity problems which occurred in the previoustests could be solved by setting the low-stage value of the IED protecting feeder Killi to400 A.

7.1.4. Sensitivity tests when using a 10 MVA synchronous generator

It was first examined whether the same 10 MVA synchronous machine would causesensitivity problems on feeder Killi. The results, however, showed that no problemsoccurred when the low-stage setting of the IED protecting feeder Killi was set to 400 A.The situation was more problematic when the same generation unit was connected tovarious nodes along feeder Ritari. In this case, the low-stage overcurrent setting of theIED was 200 A.

The machine was adjusted to operate close unity power factor when it wasconnected to node Ritari 2 by setting the “Uctrl” slider to 1.2898. It was found out thatno sensitivity problems aroused when the generator was connected to the two furthestnodes of feeder Ritari (nodes Ritari 3-4). When the generator was connected to nodesRitari 1-2, however, the IED was blinded when a two phase fault occurred at the end ofthe feeder (node Ritari 4). Other types of faults were, nonetheless, cleared correctly alsoin this case. Figure 7.3 illustrates the effect of the 10 MVA machine on the fault current

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seen by the IED. The examined fault in this case was a 0.25 seconds lasting two phaseshort circuit at the end of feeder Ritari. In the right figure there was no generationconnected, whereas, in the left figure the generation unit was connected to node Ritari 2.It can be seen from these figures that the IED can become blinded as a consequence ofthe fault current contribution of the generator.

Figure 7.3. The fault current seen by the CB protecting feeder Ritari when a two phasefault occurs at the end of the same feeder. Note the different scaling in the figures.

The low stage delay time of the IED was set to 0.22 seconds, which means that the IEDtrips only when a current pulse continuously exceeds the low-stage current magnitudesetting for 0.22 seconds. The 0.22 seconds lasting current pulses seen by the IED thatwere caused by a two phase short circuit at the end of feeder Ritari were, therefore,estimated from the simulations while the location of the 10 MVA DG unit was variedbetween different locations along the same feeder. The estimated values are shown intable 7.2. The purpose of this table is just to show effect of the blinding phenomenon,whereas, the accuracy of the single values might not be of first class since they verysimply estimated from the simulated curves. The location of the DG unit is marked withRitari 1 – 4 in the table which refer to the electrical nodes in figure 6.2. The Ik2 peakrepresents the current pulse magnitudes that were continuously exceeded for 0.22seconds, whereas, Ik2rms is the respective rms value (The IED uses rms values). Ufault

stands for the phase voltage at the fault point just before the fault.

Table 7.2. The 0.22s lasting fault current pulses seen by the IED

DG:n location Ik2 peak [kA] Ik2rms [kA] Ufault [kV]Ritari 1 0.24 0.17 12.64Ritari 2 0.24 0.17 13.17Ritari 3 0.3 0.21 13.8Ritari 4 0.49 0.35 14.53No DG 0.49 0.35 12.11

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As the table shows, the voltages at the end of the feeder (Ufault) were not withinpermissible tolerances, which of course, would not be tolerated in real life. Theincreased voltage, however, actually reduces the blinding phenomenon as it can be seenfrom equation 3.5 in chapter 3.2.1. It can be seen from the values of table 7.2 that theblinding is strongest when the DG unit was connected to the first node.

7.2. LOM protection simulation case

The purpose of this case was to examine the NDZ of a real IED. The test was carriedout in the RTDS environment using the network model already presented in chapter six.The 1.6 MVA hydro power plant was placed roughly in the middle of feeder Ritari(Node Ritari 2) as shown in the figure 7.4. The REF543 IED, which was also presentedin chapter six, was used for LOM protection of the generator. The idea in thesesimulation cases was to manually open circuit breaker 2 (marked in the figure 7.4)protecting the feeder Ritari thus creating an island situation. As already explained in theearlier chapters, the LOM protection should always disconnect the generator rapidlywhen the connection to the main network is lost. The operation of LOM protection is,however, delayed or even prevented in some cases if the active and reactive powergeneration of the generator matches closely enough with the demand in the islandedzone. The operation times of the LOM protection during various generation – demandcombinations were, therefore, captured and stored for the examination of the NDZs ofdifferent protection functions.

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Figure 7.4. The RS-CAD distribution network model used in the LOM protectionsimulations

In order to find out the shape of the NDZ in an active– reactive power coordinatesystem, the production of the generator was altered from simulation to simulation whileleaving the consumption of the loads untouched. The number of required simulationsfor determining the shape of NDZ was very high because the step size by which theproduction of the generator was increased was chosen to be 0,02 MW or 0,02 MVardepending on whether active or reactive power production was increased. The activepower production was altered from 0,1 MW to 1,6 MW while for each active powersetting the reactive power production was changed from -0,9 MVar to 1,6 MVar. Onesimulation took some 10 seconds on average which leads to the fact that determining theshape of a NDZ like this takes some 26 hours (when simulating without a pause). Thetime required for all the planned simulations would actually have been even muchgreater than that because the idea was to determine NDZs for various types of loads andfor various sets of protection functions. Rather than performing such a huge number ofsimulations controlling the RS-CAD manually, the simulations were performed byprogramming a simple program for controlling the RS-CAD runtime. This kind ofcontrol program is called a script file. The script file used for these simulations isdemonstrated by the flow chart of figure 7.5.

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Figure 7.5. The principle of the control script

In the first test case the ROCOF function in the IED was not utilized. The idea behindthis was to examine the NDZ for combined voltage and frequency functions andROCOF function separately. The LOM protection settings used in these tests can beseen from table 7.3.

Table 7.3.The settings used in the ABB REF543 IEDOperate Lower protection Higher Operate

time Treshold function Treshold timeVoltage 10 s 90% ( 18.9kV) < U < 106% (22.26kV) 10 sVoltage 0.1s 50% (10.5kV) << U << 110% (23.1kV) 0.05 sFrequency 0.2s 47 Hz < f < 51 Hz 0.2 sRocof 0.2 s 1 Hz/s < df/dt < 1 Hz/s 0.2sBlock Rocof limit 0.3 x Un

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These setting values, excluding ROCOF and the high-stage (marked by <<) setting forthe undervoltage function, are recommended for the protection of DG units connected toLV networks by the Finnish electricity association SENER [Sen 01]. The ROCOF andundervoltage settings are also realistic values although they are not found from the samelist of recommendations. Typical setting values for ROCOF in 50 Hz systems rangefrom 0.1 to 1 Hz / s according to [Aff 05]. The “Block ROCOF limit” was set very low(0.3 x Un) so that it had no relevance in these simulation studies.

7.2.1. The NDZ for over- and under frequency and voltage protection

Figure 7.6 represents the functioning of the LOM protection when the ROCOF functionis disabled. The horizontal axis stands for the real power fed from the substation beforethe opening of the CB protecting feeder Ritari, whereas, the vertical axis stands for therespective reactive power. The power fed from the substation is, of course, equal to theconsumption on the feeder plus the losses (very small in this case) minus the generationon the feeder. The origin in the figure thus represents the generation / consumptionequilibrium where the generation matches with the demand on the feeder. When Pgreater than zero in the figure, the active power consumption exceeds the active powergeneration of the DG unit which means that power is fed from the substation.Respectively, when Q is greater than zero, the reactive power consumption exceedsthe reactive power generation on the feeder. The area painted with blue colour in thefigure represents the generation / consumption combinations where the LOM protectionhas operated within 0.7 seconds, whereas, the area marked with pink colour stands forthe respective combinations where the LOM protection has operated within threeseconds.

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Figure 7.6. The non detection zone of <<U>> and <f> based LOM protection whenconstant power loads (Umin=0,5xUn) were utilized

As expected, there is a blind spot around the origin which can be clearly seen fromfigure 7.6. The blind area would be smaller if the same figure was drawn for theoperation times within five or ten seconds but, on the other hand, an unintendedislanding lasting for three seconds is already a relatively long one and surely enough tocause serious consequences. As it can be seen, the blind area is not symmetrical inrelation to the origin neither in the active- nor in the reactive power axis directions. Theasymmetry on the active power axis stems from the frequency protection settings. Asalready mentioned, the underfrequency limit was set to 47 Hz, whereas, theoverfrequency limit was set to 51 Hz. When an islanded zone has more active powergeneration compared to the consumption, the frequency starts to rise. Respectively,there will be a decrease in frequency when the active power consumption exceeds theactive power generation. The bigger the difference between active power productionand demand, the faster the frequency will change. The asymmetry in the reactive poweraxis, on the other hand, originates from the voltage limit settings. The high stage limitsetting of undervoltage protection was set to 50 %, whereas, for overvoltage therespective limit was set to 110 %. It can be seen from figure 7.6 that the boundaries ofthe NDZ in the positive reactive power direction are not met at all. This is because thevoltage never drops as low as 50 % of the nominal voltage in the simulations. The lowstage tripping limits for voltage were set to function with a ten second delay whichactually left them meaningless in all the LOM protection studies of this thesis.

It can also be seen from figure 7.6 that, unlike often presented (see figure 2.6), theform of this NDZ does not seem to be exactly rectangular in real/reactive power balancecoordinate system. The sketch of figure 7.7 illustrates the reasons for this when theloads in the power island have some dependency. The limits of the NDZ that are caused

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by the <U> function (the upper and lower limits of the NDZ area that are marked withred lines in figure 7.7) are twisted because the voltages on a feeder are, in addition toreactive power generation, also dependent on the real power balance (see equation 3.1).The more excess real power generation there is, in other words the more one moves leftin figure 7.7, the higher the voltages are already before the feeder has been isolated toan island. Since the voltage at the DG connection point (from which the relay receivesits measurements) is higher because of the produced real power, the reactive powerimbalance needed for causing the overvoltage limit to be reached is lower. Respectively,the more deficit of real power there is in the power island, that is, the more right onemoves in figure 7.7, the lower the voltages in the power island are. This, consequently,means that the more towards right one moves, the higher the required reactive powergeneration needed for causing the overvoltage protection limits to be exceeded. Thehorizontal limits of the NDZ thus bend slightly as shown in figure 7.7. This happensirrespective of the voltage dependency of the loads.

Figure 7.7. Shaping the actual form of the NDZ of LOM protection based on <f> and<U> protection when the loads have some voltage dependency

If additionally the loads in the power island have some voltage dependency, also thevertical boundaries of the NDZ bend. The phenomenon behind this bending can betterbe explained by examining the four quarters marked in figure 7.7 separately. Startingfrom the first quarter, the voltages in the power island rise when one moves downwards

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in the figure because of the excess of reactive power. Increased voltages, in turn, cause ahigher real- and reactive power demand due to the voltage dependency of the loads.This all leads to an increase in the real power unbalance since in the first quarter therewas already a deficit in real power. In the fourth quarter, the situation similar but on thisside of the vertical axis (left side) there is excess in real power. This means that as onemoves down in this quarter, the increased demand reduces the excess of real power andthus also reduces the real power imbalance. Because of the reduced real powerimbalance, one will have to travel more left (towards more real power generation) inorder to cause the overfrequency limit to be exceeded. Due to similar reasoning as incase of quarters one and two, the NDZ also bends on the upper side of the horizontalaxis. The “new areas” that are added to the NDZ because of the above explained aremarked with yellow colour, whereas, the areas that do not belong the NDZ because ofthis twisting are marked with dark grey. The more voltage dependent the loads in thepower island are, the more this NDZ twists towards clockwise direction. The loads in the first simulation, however, were of constant power type and did thushave no voltage dependency. Another approach was thus needed for explaining thebending of the frequency boundaries in figure 7.6. The same simulation case wastherefore repeated with such modifications that all the PI-line sections were removedfrom the RS-CAD draft model in order to find out whether the bending of the verticalboundaries was caused by the lines or the generator. Since the feeder Ritari nowincluded only one electrical node, all the loads were modelled as one lumped constantpower load which also included the line losses that occurred in the PI-line sections. Theresults from this simplified simulation case can be seen from figure 7.8. It can be seenfrom the figure that the vertical boundaries of the NDZ are now roughly straight lineswhich means that the bending of the boundaries in figure 7.6 was caused by the PI-linesections. It can also be seen from figure 7.8 that the vertical boundaries are more ruggedcompared to the boundaries in figure 7.6. This shows that the PI-sections stabilized thepower imbalance oscillations to some extent.

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Figure 7.8. The non detection zone of <f> based LOM protection in a simulation whereno PI-sections were included in the draft model. Constant power loads (Umin=0,5xUn)were used in this simulation.

Figure 7.9 illustrates the functioning of LOM protection when ROCOF function isincluded. Only the surroundings of the origin are depicted in the figure, because largeractive- and reactive power imbalances are not interesting from the NDZ point of view.From this figure it can be seen that the NDZ for operation times within three seconds(pink area) is only slightly reduced compared to the situation when ROCOF functionwas not included (figure 7.6), whereas, the NDZ for operation times within 0.7 seconds(blue area) is considerably reduced when ROCOF is included. This could stem from thefact that there is usually a small sudden dip or increase in frequency which is quiterapidly eliminated by the response of the generator. The simulations indicated that thissudden change in frequency was not large enough to cause the tripping of frequencyprotection but it could, in many cases, have been large enough to cause the tripping ofROCOF function. After these initial changes, the frequency seemed to declineconstantly in a linear fashion which would likely not have caused the ROCOF to trip.This explains why the NDZ of ROCOF after three seconds does not seem to beconsiderably smaller compared to the NDZ where ROCOF was not included. All in all,the comparison between the results shown in figures 7.6 and 7.9 clearly shows that theROCOF feature remarkably enhances the functioning of LOM protection.

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Figure 7.9. The non detection zone of <<U>>, <f> and ROCOF based LOMprotection when constant power loads (Umin=0,5xUn) were utilized

The effect of the voltage dependency of the modeled loads on the form of NDZs in thepower island was also studied. Figures 7.10, 7.11 and 7.12 represent the NDZs ofcombined frequency and ROCOF protection when the loads in the power island weremodeled as constant power loads (figure 7.10), constant current loads (figure 7.11) andconstant impedance loads (figure 7.12). The comparison between the figures shows thatthe blind area twists towards clockwise direction when the loads are made voltagedependent. The reason for this twisting is similar to what was already explained abovein figure 7.7. Thus, the more voltage dependent the loads are the more does the NDZtwist towards clockwise direction. Two more figures of NDZ can be found fromappendix 5. In these two NDZ figures the effect of the load dependency on basicfrequency LOM protection is studied in a simplified case where all the PI line sectionsare removed from the network model.

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Figure 7.10. The non detection zone of ROCOF and <f> based LOM protection whenconstant power loads (Umin=0,5xUn) were utilized

Figure 7.11. The non detection zone of ROCOF and <f> based LOM protection whenconstant current loads (Umin=0,5xUn) were utilized

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Figure 7.12. The non detection zone of ROCOF and <f< based LOM protection whenconstant impedance loads (Umin=0,5xUn) were utilized

The examination of the NDZ of various LOM protection functions shows that there is areal risk for undetected islanding. Especially the commonly utilized simple combinationof frequency and voltage protection seems to have a large NDZ. The addition ofROCOF to voltage and frequency protection seems to remarkably enhance the detectioncapability. However, even this combination appears to be unable to detect islanding inthe presence of relatively large reactive power imbalances when the active powerimbalance is small. Stricter voltage protection settings would, of course, reduce thisNDZ considerably since in these simulations the high stage setting of the undervoltagethreshold was set as low as 50 % of the nominal voltage. This may, nevertheless, not beallowed in future since it is anticipatable that FRT requirements are diffusing also to DGunits as well.

It would be beneficial for network companies to have some kind of roughunderstanding of the size of the NDZ every time new DG units are connected. Theassessment of the NDZ in each case is unfortunately quite complicated as the simulationresults above indicate. The assessment is quite complicated since there are so manyinfluencing factors such as the voltage and frequency dependency of the loads in thepower island, the type and size of the generators as well as the type of the excitationsystem of the machine in the power island and also the electrical parameters of thepower island network. A good solution for this problem would undoubtedly be a toolintegrated in NIS which was able to assess the size of the NDZ and to estimate theprobabilities for unintentional islanding. The problem of unintentional islanding could,of course, also be tackled by equipping all DG units with a LOM protection technologythat is not prone to the NDZ problem. Communication based LOM protection is one ofsuch solutions but it would naturally require some additional capital.

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8. CONCLUSIONS

The rapidly increasing amount of DG is raising new challenges to distribution networks.Protection issues, voltage rise problems, power quality problems and raising fault levelsare the most serious of these challenges caused by DG. These problems can greatlyrestrict the popularity of DG if distribution networks are managed passively as today.The basic characteristics of passive network management are the simple networkreinforcement approach by which it creates extra capacity and the way of treatinggeneration units merely as negative loads (fit and forget philosophy). The problem withthis kind of replacement strategy is that it causes very high costs which, depending onthe cost allocation, can render DG economically unfeasible.

The problems caused by DG to distribution networks can often be fixed by justsimply changing existing network components to new ones with higher ratings. Thistraditional way is, however, just simply too expensive and it leads to a fairly lowutilization rate of the network assets. Instead of this traditional passive way of operatingdistribution networks, networks can alternatively be managed in a more intelligentmanner. This is done by intelligently controlling the various existing active resourcessuch as DG units, controllable loads, reactive power compensation devices, energystorages and the tap changers of HV/MV transformers in such a way that theseresources support the network. This approach, which is called active networkmanagement (ANM), does not necessarily require any investments on primary networkcomponents like conductors and transformers since the existing capacity is used moreprecisely. Investments on secondary components like local controllers, networkmanagement systems and communications are, however, needed. The benefits broughtby the active management will, nevertheless, very likely outweigh the costs of theinvestments on secondary network components.

Active network management offers effective solutions to voltage rise problems. Thevoltages in the network can be kept within limits by using various active resourcescapable for consuming reactive power. Most DG units are already capable of controllingtheir power factor and thus consuming reactive power. This is a fairly simple but yeteffective way to increase the amount of allowable DG capacity but it necessitatesappropriate ancillary service contracts between the DNO and the owner of thegeneration unit in question. When this type of simple control is not sufficient, othermore effective types of reactive power compensation equipment like FACTS devicescan also be harnessed for maintaining the voltages within tolerances. FACTS also havethe advantage that they are capable of eliminating power quality problems like flickerand harmonics. These above mentioned voltage control tools can be based on local

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measurements and control but the control can also be based on coordinated controlcenter systems like DMS for better optimization of all the resources. Coordinatedvoltage control can also make better use of the OLTC of the HV/MV transformer(s).

The utilization rate of distribution networks that are dimensioned according to thedeterministic N-1 criteria is low. Power flow management tries to make use of the sparecapacity that would be unused if the network was managed according to the passivemanagement. This is achieved by allowing some extra DG capacity in addition to thecapacity determined by the N-1 criteria. The extra DG capacity units would be allowedto run freely whenever possible but in the occurrence of congestion caused by a faultedcomponent these units were subject to trimming or tripping depending on theseriousness of the congestion. The risk for the extra capacity units of being trimmed ortripped in congestion conditions would be compensated by offering cheaper connectioncosts to these units.

There has traditionally been very few if any generation units connected to MVdistribution networks. The power flow in distribution networks has, therefore, beenunidirectional which has enabled the utilization of relatively simple protection schemes.DG, however, can change the magnitudes and directions of power flows in distributionnetworks which complicates the situation from the network protection point of view.The fault current contribution of DG units can, for example, cause protection blinding,protection selectivity and failed reclosing problems. These problems can be solved bysubstituting commonly used non-directional overcurrent relays by more advancedprotection schemes such as directional overcurrent-, distance-, and differentialprotection. Probably the trickiest of the protection problems is, however, related to theloss of mains (LOM) protection of DG units. LOM protection makes sure that nounintentional power islands are formed in distribution networks. Combined voltage andfrequency protection is probably the most utilized LOM protection scheme because it isapplicable to all types of generation units. The problem of this, and also most of theLOM protection schemes, is the fact that it cannot detect islanding if production andconsumption in the islanded zone match closely enough with each other. The blind areain which LOM protection fails to detect islanding is called the non detection zone(NDZ). The NDZ is usually depicted in a coordinate system whose horizontal axisrepresents active power imbalance and whose vertical axis represents reactive powerimbalance.

Wind power capacity has been steadily growing in the recent years. In areas, wherethe share of wind power has already reached significant levels, the local TSOs haveunderstood that wind power cannot be allowed to be operated completely independentlyfrom the rest of the power system. Because of this, FRT requirements specifying therequirements on the behavior of wind generators during voltage dips have been issuedby these TSOs. These requirements give the voltage dip depth and form which thegeneration units need to be able to ride through without losing their stability. At themoment, these requirements are mostly made for wind farms connected to highervoltage levels but it is foreseeable that similar kinds of requirements will eventually

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diffuse to distribution network connected DG units as well. If this will be the case, thenattention has to be paid to the coordination between LOM protection settings and FRTrequirements. It is of no help at all if a DG unit has FRT capability but the LOMprotection has been set so tight that it does not allow the DG unit to ride through thefault.

DG units may also be required to provide certain power system level ancillaryservices like primary frequency control in the future. Many DG units are, however, toosmall to attend many system level services. The utilization of virtual power plant (VPP)can solve this problem. It can be used to aggregate large number of active resources andsell this entity as one service whose characteristics the VPP can determine by choosingsuitable resources from its selection. To the TSO, this service offered by the VPP wouldseem like any other service offered by conventional central power plants.

The common protection problems caused by DG were studied more closely in thisthesis. The studies were carried out by utilizing real commercial IEDs in a real timesimulation environment. The real time digital simulator (RTDS®), which was used inthese studies, performs all its calculations in real time which makes it possible toconnected external physical devices to function as a part of the simulation. A networkmodel representing a real Finnish distribution network was modeled with dedicatedCAD software (RS-CAD) and the IEDs were set to control the CBs in this modelednetwork. A combined current and voltage amplifier had to be used for amplifying thecurrent and voltage signals (the measurements for the IEDs) to a realistic scale for theIEDs.

Problems related to protection blinding and to protection selectivity were firstexamined. A modern non-directional overcurrent IED was used for controlling a feederCB in these studies. It was found out that a relatively large generator was needed forcausing problems for the utilized overcurrent IED when its settings were doneappropriately. The simulations, however, revealed that some changes to the settings maybe necessary for correct operation of the IEDs when new DG units are connected. It isthus very important that the engineers responsible for network protection planning innetwork companies are aware of the effects of DG. There may, nevertheless, be somemore difficult situations in other networks where more sophisticated protection schemeslike distance or differential protection are needed.

The functioning of LOM protection was also studied. A multifunctional IED wasconfigured to function as LOM relay for these studies. The functioning of frequency andvoltage protection schemes was first studied after which also the rate of change infrequency (ROCOF) protection scheme was included. In these studies, the LOM relaywas set to control the circuit breaker (CB) connecting the DG unit. The power islandwas created by opening the feeder CB which was protecting the feeder on which the DGunit was located. This was repeated for myriad times while for each time changing theoutput of the DG unit and thus also the active- and reactive power equilibrium in thepower island. After a large number of simulations like this, the NDZ for each LOMprotection scheme was attained. As expected, the blinding of LOM protection was

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found to be a real problem. Voltage and frequency protection based LOM protectionespecially suffers from a large NDZ. ROCOF was found to have a considerably smallerNDZ. The size of the NDZs can, of course, be reduced by applying stricter settings butthis, on the other hand, can cause nuisance tripping. Care must, therefore, be taken whenchoosing appropriate settings for various LOM protection schemes. In the future onewill probably also have to take into account the fault ride through (FRT) requirements ifDG units are required to support the power system. LOM protection settings are alwaysa compromise between having small NDZ and enabling FRT.

All in all, active network management seems to be a wiser way to accommodatelarge amounts of distributed generation compared to passive network management.Many active network features like active voltage- and power flow management arealready technologically possible. It is also possible to solve all the protection problemscaused by DG with existing modern IEDs. There are, however, also some issues thatstill need to be solved like the fact that existing NISs and DMSs are not capable of fullytaking DG into account. Some more research is thus needed on certain active networkfeatures. It is also evident that a functioning commercial framework that encouragesnetwork utilities to adopt active network management features is necessary forwidespread adoption of active network management.

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Appendix 1: Smart grid vision of the EU

Figure A.1. The smart grid vision of the EU [Eur 06]

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Appendix 2: Communication in distribution networks

Table A.1. Various communication technologies for distribution networks [Ber 07]

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Appendix 3: The connection diagram of REF543 IED

Figure A.2. The connection diagram of the utilized REF543 IED

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Appendix 4: The connection diagram of the REF615 IED

Figure A.3. The connection diagram of the utilized REF615 IED

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Appendix 5: Non-detection zones of LOM protection

Figure A.4. The non detection zone of <f> based LOM protection in a simulation whereno PI-sections were included in the draft model. Constant current loads(Umin=0,5xUn) were used in this simulation.

Figure A.5. The non detection zone of <f> based LOM protection in a simulation whereno PI-sections were included in the draft model. Constant impedance loads(Umin=0,5xUn) were used in this simulation.