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Active Distribution System Management

A key tool for the smooth integration of distributed generation full discussion paper

A EURELECTRIC paper, FEBRUARY 2013

Theis the sector association representing the common interests ofthe electricity industry at pan-European level, plus its affiliates and associates on several other continents.In line with its mission, EURELECTRIC seeks to contribute to the competitiveness of the electricity industry, toprovide effective representation for the industry in public affairs, and to promote the role of electricity both in theadvancement of society and in helping provide solutions to the challenges of sustainable development.EURELECTRIC s formal opinions, policy positions and reports are formulated in Working Groups, composed ofexperts from the electricity industry, supervised by five Committees. This structure of expertise ensures thatEURELECTRIC s published documents are based on high-quality input with up-to-date information.For further information on EURELECTRIC activities, visit our website, which provides general information on theassociation and on policy issues relevant to the electricity industry; latest news of our activities; EURELECTRICpositions and statements; a publications catalogue listing EURELECTRIC reports; and information on our events andconferences.

Dépôt légal:D/2013/12.105/7

EURELECTRIC pursues in all its activities the application ofthe followingsustainable development values:Economic DevelopmentGrowth, added-value, efficiencyEnvironmental LeadershipCommitment, innovation, pro-activenessSocial ResponsibilityTransparency, ethics, accountability

Akey tool forthesmooth integration of distributedgeneration--------------------------------------------------------------------------------------------------PerHALLBERG (SE) ChairJuan Jose ALBA RIOS (ES); Christer BERGERLAND (SE); Aurelio BLANQUET (PT); Marcel CAILLIAU (BE); ConorCLIFFORD (SE); Paul DE WIT (NL); Ellen DISKIN (IE); Håkan FEUK (SE); Bruno GOUVERNEUR (BE); Mike KAY(GB); Pauline LAWSON (GB);Marina LOMBARDI (IT);Pavla MANDATOVA (EURELECTRIC Secretariat);RuudOTTER (NL); Pablo SIMON CABALLERO (ES); Jorge TELLO GUIJARRO (ES); Walter TENSCHERT (AT); DavidTREBOLLE (ES); Siegfried WANZEK (DE)Contact:Gunnar LORENZ, Head of Networks Unit glorenz@eurelectric.orgPavla MANDATOVA, Adviser Networks Unit-pmandatova@eurelectric.org

1.1.Distributed Generation: Facts and Figures.....................................................................................21.2.Key Challenges for Current Distribution Networks........................................................................42.1.Key Building Blocks.......................................................................................................................102.2.Distribution Network Development, Planning, Access & Connection.........................................142.3.Active Distribution Network Operation.......................................................................................182.4.Technical Development: Towards Flexible Distribution Systems................................................27A.Demonstration of active power effect in voltage control Networks 2025 Project, Spain........34B.Active voltage management using wind generation voltage control and reactive capabilities ESB Networks, Ireland..................................................................................................................36C.Technical Control Strategy for Active System Management EDP Distribuicão, Portugal.........38D.Protection and Automation Strategies in MV Networks Enel Distribuzione, Italy...................39E.Integration of RENEWABLES in MV and LV Networks E.ON Bayern, Germany........................40A.Automation and Control in MV & LV Distribution Networks.......................................................42B.Curtailment of Distributed Generation........................................................................................45

Figure 1 Common voltage connection levels for different types of DG/RES.....................................................2Figure 2 Distributed generation installed capacity and peak demand in Galicia, Spain....................................3Figure 3 Installed capacity of photovoltaic installations in the E.ON Bayern grid (Source: E.ON).....................3Figure 4 Power flows between transmission and distribution network in Italy, 2010-2012 (Source: EnelDistribuzione).....................................................................................................................................................4Figure 5 Relation between the degree of DG penetration and grid losses (Source: van Gerwent)...................5Figure 6 Instability in distribution system(Source: Mainova)............................................................................6Figure 7 Reverse power flows at a substation in northwest Ireland(Source: ESB Networks)...........................7Figure 8 Current DSO networks..........................................................................................................................9Figure 9 Three-Step Evolution of Distribution Systems....................................................................................11Figure 10 DSO interactions with markets & TSO at different time frames......................................................12Figure 11 Variable accessapproach (Source: EWE Netz).................................................................................16Figure 12 Extension of network capacity for peak load versus a load management solution (Source: EWENetz).................................................................................................................................................................17Figure 13 Market and network operations......................................................................................................19Figure 14 Instability in the distribution system................................................................................................21Figure 15 Information Exchange Today and in the Future...............................................................................23Figure 16 An illustrative example of a traditional approach to voltage control..............................................24Figure 17 Comparisonof BAU distribution Investments and maintenance costs (WP4) and costs whenapplying ANM solutions (WP5) for the Spanish network.................................................................................33Figure 18 R/X ratio effect in voltage control....................................................................................................34Figure 19 Extra reactive power contribution to maintain a voltage setpoint..................................................34Figure 20 DG effect in the voltage triangle design...........................................................................................35Figure 21 Wind farm active and reactive capabilities as demonstrated in ESB Networks Volt / VAr trials.....36Figure 22 Test network for field demonstration of coordinated Volt / VAr Control........................................37Figure 23 Active and reactive power where wind farms connect to substation-as active export increases,reactive power is imported to control PCC voltage.........................................................................................37Figure 24Hot spots areas in E.ON Bayern (installed RES capacity in EBY grid areas)......................................40Table 1 Three-Step Evolution of Distribution Systems in detail.......................................................................13Table 2 New System Services at Distribution Level..........................................................................................20Table 3 Voltage control in current distribution networks................................................................................25Table 4 Technology optionsfor distribution network development...............................................................28Table 5 DG Contribution to voltage control by voltage level...........................................................................35

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Theexpansionof decentralised and intermittent renewable generation capacities introduces newchallengestoensuring the reliability and quality ofpowersupply.Mostof these newgenerators(both in number and capacity) arebeingconnected to distribution networks atrendthatis set tocontinue in the coming years.This development hasprofound implications for distribution system operators(DSOs). Untilrecently, DSOsdesigned andoperateddistribution networksthrougha top-down approach.Predictable flows in theelectricitynetwork did not require extensive management and monitoringtools.Butthismodel is changing. Higher shares of distributed energy sources lead tounpredictablenetwork flows,greatervariations in voltage,and different network reactive power characteristics.Local grid constraints will occur more frequently, adversely affectingthe quality of supply.YetDSOs areneverthelessexpected tocontinue tooperate their networks inasecure way and toprovide high-quality service totheircustomers.This EURELECTRIC report addressesanumber of fundamental questionsthatarisefrom theintegration ofdistributed generation(DG)and otherdistributed energy resources(DER)into theenergy system:iiiiiActive distribution systemmanagement may provide someanswers to these questions.Indeed,distribution management will allow grids to integrate DERefficientlybyleveraging the inherentcharacteristics of this type ofgeneration.The growth ofDER requireschangestohowdistributionnetworks are planned and operated. Bi-directional flows need to be taken into account:they mustbemonitored, simulated and managed.The reportsets out implications forthetasksof system operators (TSOs and DSOs) and DG/RESoperatorsandoutlinesoptions for system planning and development, system operation,andinformation exchange,therebyopeningthe doorfor further analysis. It focuses on outstandingtechnical issues and necessary operational requirementsand calls foradequate regulatorymechanismsthat wouldpave the way forthese solutions.The paperfocuses largelyondistributed generation a challengemanyDSOs arealreadyfacingtoday. However,the presentedpossiblesolutionswill generally also beapplicabletootherflexibility providers like loadsandelectric vehicles, which fall under theumbrellaofflexibilityoffered by DER.

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include distributed/decentralised generation (D G) anddistributedenergy storage (DS)1.WiththeEU on its way to meeting a 20% target forRESin total energy consumptionby 2020, the share of electricity supply from RESis on therise. Intermittent RESlikesolar and wind addanadditional variabletothe system that will requiremoreflexibilityfrom generation (including RES) anddemandand investments in network infrastructure.Suchintermittent RESwill be connected largely toEuropean distribution systems.At the same time, electrification of transport will be needed to furtherdecarbonise the economy. For a significant deployment of electric vehicles by 2050, Europe needs to targeta 10% share of electric vehicles by 2020. These vehicles will need to be charged through theelectricalsystem. Together with the electrification of heating and cooling, these trends will contributetofurtherevolutionof European power systems.aregenerating plantsconnected to the distribution network,often with small to medium installedcapacities,as well as medium to larger renewable generation units.Due to high numbers , they areimportant compared to the size of the distribution network.In additiontomeetingon-site needs,theyexport the excesselectricityto the market viathelocal distribution network.DG isoften operated by smaller power producers or so-called prosumers.Unlikecentralisedgeneration,which is dispatched in a market frameunderthe technical supervision ofTSOs, small DG is oftenfullycontrolled by the owners themselves. The technologies include engines,windturbines, fuel cells and photovoltaic(PV)systemsand all micro-generationtechnologies.In addition tointermittent RES,an important share of DG is made up ofcombined heat and power generation (CHP),based oneitherrenewables (biomass) or fossil fuels. A portion oftheelectricity produced is used on site,andanyremainderisfed into the grid.By contrast,in case of CHPthegeneratedheatis always used locally,as heat transport is costly andentailsrelatively large losses.Figure1provides anoverview of generationtypes usually connected at different distribution voltage levels.HV(usually 38-150 kV)Large industrial CHPLarge-scale hydroOffshore and onshorewind parksLarge PVMV(usually 10-36 kV)Onshore wind parksMedium-scale hydroSmall industrial CHPTidal wave systemsSolar thermal and geothermal systemsLarge PVLV (< 1kV)Small individual PV, Small-scale hydroMicro CHP, Micro windFigure1Common voltage connection levels for different types of DG/RES1Storage is not only a resource but also an off take/load.Electric vehicles could be used as storage in the future.

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Thefollowing examples demonstrate thata move from mere DG connection toDG integrationis a mustalready todayin some countries. As illustratedinFigure2,in, theinstalled capacity ofDGconnectedto thedistribution networks ofUnion Fenosa Distribución (2,203 MW) represents 120% of thearea stotal peak demand (1,842 MW).2

Figure2Distributed generationinstalled capacity and peak demand in Galicia, Spain(Source: Union Fenosa Distribución)Intheregional distribution network in the(seeFigure3),the installed capacity ofintermittentrenewableDGalreadyrepresents a large percentage of the peak load.In many places, theDGoutputofdistribution networksalreadyexceedslocalload sometimes by multiple times. From theTSO point of view,theDSO network then looks like a large generator in periods with high RES production.

*status for 31December 2012Figure3Installed capacity of photovoltaicinstallations intheE.ON Bayerngrid (Source: E.ON)2Overall, DGcovers more than 30% of Union Fenosa Distribución regionalenergy (MWh)demandalready today.

Natural GasCHP 7,6%

Rest CHP14,5%

Wind power62,1%

PV0,5%

Hydro13,9%

OtherRenewables1,4%

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In 2011, 10 GW of PV were newly connected to Italian distribution grids (Enel Distribuzione), the highestyearly increase in distributed generation connected to the grid worldwide.InnorthwestIrelandwitha peak demand of 160MW,307.75 MW of distributed wind generationarealreadyconnected tothe distribution system, and a further 186 MWarecontracted orplanned.Beyondthis, another 640 MW of applications have been submitted., due to its proximity to the loads, distributed generation shouldcontribute to thesecurity ofsupply, power quality, reduction of transmission and distribution peak load and congestion, reduced needfor long distance transmission, avoidance of network overcapacity, deferral of network investments andreduction in distribution grid losses (via supplying active power to the load and managing voltage andreactive power in the grid)., integrating distributed generation into DSO grids represents a capacity challenge due to DGproduction profiles, location and firmness.This poses important challengesforbothdistributionnetwork developmentandoperation.For example, peak residential demand frequently correspondsto moments of no PV production.Figure4shows the situation inthe southern Italian region of Puglia. Itindicates the incredible increase inthepower installed and energy produced from PVsinrecentyearsand the subsequentevolution of powerflows at the connection point between the transmission network and the distribution network.As the peakload corresponds to literally zero PV production, there is no reduction in investment ( netting generationand demand).

Figure4Power flows between transmission and distribution network in Italy, 2010-2012 (Source: Enel Distribuzione)

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Network connection studies and schemes forgenerators are designed to guarantee that under normaloperation all capacity can be injected at any time of the year.4The current European regulatory frameworkprovides forpriority andguaranteed network access for electricity from RES (Art. 1 6 o f RES Directive2009/28/EC) and RES-based CHP (Art. 14 of the new Energy Efficiency Directive 2012/27/EC).RES-E ismostly connected on a firm/permanent network access basis(butcannot be considered as firm for suchdesign purposes).Generation and load ofequivalent sizesimply different design criteriaas e.g. wind and PVhaslower diversity thanload. In addition,wider cables to lower the voltagemight be needed.The contribution of DG to the deferral of network investments holds true only for arelatively smallamount and size of DG andforpredictable and controllable primary sources. Article 25.7 of Directive 2009/72/EC requires DSOs to take into account distributed energyresources and conventional assets when planning their networks. This may be complicated whenapplications for connection are submitted at short notice and DSOs receive no information on connectionto private networks. Situations will occur when DSOs have large amounts of DER connected to theirnetwork and the resulting net demand seen further up the system hierarchy is lowered. Virtual saturation a situation when the entire capacity is reserved by plants queuing for connection that may not eventuallymaterialise may also occur as generator plans cannot be firmbefore the final investment decision.However, even in the cases when the project is not built, it occupies an idle capacity which may lead newgrid capacity requeststo face increased costsin case network reinforcements are needed.The situation is similar in case ofgridlosses (related costs arepart of DSOs OPEX).Figure5demonstratesthat witha lowshare of DGthese lossesdrop,but once there are large injectionsof DG into the DSOnetwork and load flows over the network,grid lossestend to increase. DGcanreduce networkcosts intransportlevels but entails higher costs inthelevelto whichit is connected.

Figure5Relation between the degree of DG penetration and grid losses (Source: van Gerwent)3In some countries, this regulation is part of the regulation for feed-in of renewable energy or other preferentialpower production and remuneration.4In some countries this is also the case for the N-1 contingency statewhich istypically considered in ameshednetwork and represents the fail of a grid element. Many MV networks are meshed even when they are operatedradially, so some N-1 is also possible in MV.

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In addition, distributed generation, in particular intermittent RES, poses a challenge not only for systembalancing, but also for local network operation.(statutory limitsforthe maximum and minimum voltage ensure thatvoltage is keptwithin the proper margins and isneverclose to the technical limitsof the grid)(thermal rates oflines, cables, transformersthatdeterminethepossible power flow).A distribution systemcanbe drivenout ofitsdefined legal and or physical operating boundaries due tooneor both of the following:iInjection of active power leadstovoltage profile modifications.Reversed power flows(flo ws fromdistribution totransmission)occur when DG productionexceeds local load.Themore local production exceeds local demand, thestrongerthe impactonvoltage profiles.Figure6illustrates such situations.DSOs may have difficulties in maintaining the voltage profile at the customer connection points, inparticular on LV level,as active voltage control is not in place. In most countries, monitoring of gridvalues is missing andmost distributed generators are not equipped to participate in systemmanagement no active contribution of generation to network operation is expected.5As a result,operational system security may be endangered and security of facilities (bothcustomers installationsand the network as such) put at risk.

Figure6Instability in distribution system(Source: Mainova)iWhen excessiveDGfeed-in pushes the system beyond its physical capacity limits(PG-PL>Pmax),congestions may occur in distribution networks. Thismay lead tonecessaryemergencyactions tointerrupt/constrain offgeneration feed-in or supply.A similar situation can occur in case of excessivedemand on the system(PL-PG> Pmax). Thiscould applytohigh load incurrede.g.bycharging of electricvehicles, heat pumps andelectricalHVAC (heatingventilation andair-conditioning).

5Where DSOsare already in the reactive DSO phase(see section 2.1), these solutions have been implemented.

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Generation curtailment is used in cases of system security related events (i.e. congestion or voltagerise) . Theregulatory basis for generation curtailment in such emergency situationsdiffers acrossEurope.6In some countries(e.g. in Italy, Spain, Ireland), the control of DG curtailment isin TSOhands: the DSO can ask the TSO,who is able to control active power of DGabove acertain installedcapacity,to constrain DG if there is a local problem.7As the TSO is not able to monitor distributionnetwork conditions (voltage, flows), DSOs can only react to DG actions. This can result in deterioratingcontinuity on the distribution system which will impact both demand customers and DG.Annex 3.Bprovides an overview of thesituation in different countries.Figure7showsthereverse power flowson an Irish substation in an area with high wind penetration.

Figure7Reverse power flows at a substation in northwest Ireland(Source: ESB Networks)

6Curtailment/feed-in management rules are either not defined by law at all (e.g. Austria), defined at the TSO levelonly (e.g. Spain or Italy) or defined at both the TSO and the DSO level (e.g.UK orGermany according to the revisedfeed-in law).7The TSOmight even issue V, Q or pf set points to DG on the distribution system.8DSOsare responsible for ensuring the long-term ability of the system to meet reasonable demands for thedistribution of electricity and for operating, maintaining and developing under economic conditions a secure, reliableand efficient electricity distribution system in their area with due regard for the environment and energy efficiency(Article 25(1) of Directive 2009/72/EC).

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In sum, the keychallenges for DSOs includeito accommodate new DG connections:Network operators are expected to provide an unconditional firm connection which maycause delays or increase costsforconnecting embedded generation;Increased complexity for extension(including permitting procedures)and maintenance of thegrid may require temporarylimitation for connection ofend customers.ibut also faultlevels and system perturbations like harmonics or flickers;when flowsexceedthe existing maximum capacity,which may resultin interruptions of generation feed-in or supply;after network failuredue toanincreased number and severity ofsuch faults.i Depending on the size of a DG/RES&DERsystem, DSOsmay requirea newconnection at a particular voltage level.They may refuse accessto the gridonly when they can prove that they lackthe necessary network capacity (Art. 32 of Directive 2009/72/EC).i This includescontrol, monitoring and supervision,as well asscheduled and non-scheduled outage management.DSOs are responsible for operations directly involving their own customers. Theysupport the TSOs,who are typically in charge of overall system security,whennecessary in a predefined manner, eitherautomatically or manually (e.g.via load shedding in emergency situations).Such systems ofcooperation for intervention in generation and demand incases of system security events are definedin detail in national regulations.A common basis for these rulesisnowbeingsetin theEU-widenetworkcodes (operational security, balancing, congestion management,etc.).i (commonl y assesse d b y zon al index es suc h asaverageduration of interruptions per customer per year (SAIDI)andaverage number of interruptions percustomer per yea(SAIFI)or individual indexes like number and duration of interruptions)(maintaining voltage fluctuations on the system withingivenlimits). In planning, the DSO ensures that networks are designed to maintain these standardsregardless of power flow conditions. However in cases of network faults, planned outages or other9National regulatory authorities (NRA) have the duty of setting or approving standards and requirements for qualityof supply or contributing thereto together with other competent authorities (Article 37(1h)of Directive 2009/72/EC).

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anomalous events, the DSO must undertake switching actions so that adequate supply quality ismaintained. While to date this has beenratherstatic, increasingly automation or remote switchingwill need to be undertaken to ensure near real-time fault isolation and restoration of supply.Voltage quality is impacted by the electrical installations of connectednetwork users. Thus the task of the DSO in ensuringvoltage quality must account also for theactions of network users, adding complexity and the need for both real-time measurement andmitigating resources (i.e.on-load voltage control) and strict network connection criteria. Europeanstandard EN 50160 specifies that the maximum and minimum voltage at each service connectionpoint must allow an undisturbed operation of all connected devices. Voltage at each connectionshould thus be in the range of±10%oftheratedvoltage under normal operating conditions.Insome countries, compliance with these or other specified national voltage quality requirementsthat can be even more restrictive represents part of DSOs contractual obligationsand qualityregulation. In some countries,network operators are required to compensatecustomersin casethe overall voltage quality limitsare breached.10The fundamental topological design of traditional distribution grids has not changed much over the pastdecades.Up until recently, DSOs have distributedenergyand designed their grids on a top-down basis.Under the paradigm networks follow demand , their primary role was to deliver energy flowing in onedirection, from the transmission substation down to end users.This approachmakesuse of very fewmonitoring toolsandis suitable for distribution networks with predictable flows.Because ofthedifferent development of electrification, distribution networks characteristics differ fromcountry to country.Voltage rate levels are usually distinguished as LV, MV or HV.11As illustrated inFigure8the level of supervision, control and simulation in HV distribution networks is close to that of TSOsintheirnetworks. MV and LV networks are mostly rather passive hereDSOslack network visibility and control.The lower the monitoring level,the lower the operational flexibility.For more detailed information onautomation and control see results of a survey conducted amongEURELECTRIC membersin Annex 3.A.

Figure8Current DSO networks

10CEER Benchmarking report, 2011.11CENELEC standard EN 50160 (2010) uses followingtheclassification: LV < 1kV, MV 1kV 36 kV, HV 36-150 kV.

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Traditional distributionnetworks have different characteristics in topology (meshed or radial), operationtype (meshed or radial), number of assets and customers, operational flexibility and monitoring level:i(also called sub-transmission) are quite similar to transmission networks. The topologicaldesign of the grid is meshed and may be operated as radial or meshed depending on the situation. HVnetworks are operated in a similar way all around Europe: N-1 or N-2 contingency criteria12are usuallyin place for ruraland urban areas, respectively. The monitoring level at HV is very high. DSOsoperatingHV gridsare able to supervise and control the HV network from the control room centres.isignificantly differ in their characteristics with respect to urban and ruralgrids. Mostly, meshed topology is used that can be operatedeitheras meshed (closed loop) or radial(open loop). In some countries or depending on the network type in a region,MV operation mayalways be radial. A high density of loads and relatively high demand typically causes high equipmentload factors (transformers, cables) for urban areas. Rural areas are characterised by larger geographicalcoverage and lower load densityand thus longer lines, high network impedances and lower equipmentload factors. iare usually radially operated. Similar to MVnetworks, urban and rural LVnetworkshavedifferent characteristics.pOnce DG in distribution networkssurpasses a particular level, building distribution networks able to supplyall load& DG within the existing quality of service requirements will frequently be too expensive andinefficient.For example, in many places the network wouldonlybeconstrainedforfew hours per year. Inaddition, the security of supply and quality of serviceproblems will no longer be limited to specificsituations.Integrating the high amount of existing and projected DG and, later, other DER will require new ICTsolutions and an evolution of the regulatory framework for both network operators and users.Networkplanning and operation methodologies need to be revised to take thenew solutionsinto account.There is noone-size-fits-all solution because distribution networks are rather heterogeneous in terms ofgrid equipmentandDGdensity at different voltage levels. Every distribution network should be assessedindividually in terms of its network structure (e.g . custom ers an d connecte d generato rs) and publicinfrastructures (e.g. load and population density).Nevertheless, theneededdevelopment towards futuredistribution systemswhich meet the needs of all customers can be described in the three schematic stepspictured below: from(1)passive network via(2)reactive network integration to(3)active systemmanagement.

12Ruleaccording to which elements remaining in operation after a fault of a distribution system element must becapable of accommodating the new operational situation without violating the operational limits.

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Figure9Three-Step Evolution of Distribution SystemsThis approachimplies resolving all issuesat the planning stage, which may lead to an oversized network. DSOsprovide firm capacity(firm grid connection and access)that may not be fully used anymore due tolocal consumption of the electricityproducedbyDG. This approach has the advantage of requiringlow flexibility, control and supervision, but is only possible for a network with very low DERpenetration.Once DER penetration rises, the system cannot be designed to cater for allcontingencies without verysignificant investment in basic network infrastructure, making thisapproach less economical. Thisapproach is used today in some countries with a high share of DG.Theregulation requiresconnecting as much DG as possiblewith no restrictions.Congestions (or other grid problems) aresolved at the operation stage by restricting both load and generation. This solution could restrictDG injections during many hours per year and lead to negative business case for DG if they are notremuneratedfor the restrictions.Already today, some front-runner countries with high DGpenetration levels can be considered as having reached the interim reactive network integration stageat whichDSOs solve problems once theyoccur(largely only in operation). The existing hosting capacity of the distribution network can be usedmore optimally if other options including ICT, connection& operationalrequirements guaranteeingadequate performance of DER towards the system(i.e . v ia grid codes)and market-basedprocurement of ancillary services from DER are considered.Operational planning of distributionnetworks(similar tothatat transmission level)wouldbe in place in networks with high DER sharesin order to incentivise dispatchin a way that is compatible with the network.Improved networkcapacity planning and congestion management at distribution level at different times and locationswill be requiredtomaximise the level of generation which is injected in the most economicalwayfor all parties, while maintaining network stability.DSOs musthave tools foroverseeingmaintenance ofnetwork standards. Additionally they should have the possibility to buy flexibilityfrom DG and load in order to optimise network availability in the most economic manner or tomanage network conditions which are beyond the contracted connection of the customers.DSOsshould have the possibility to buy flexibility from DG and loadon so-called flexibility platforms inorder to solve grid constraints.The network reinforcement could be deferred until the momentwhen it becomes morecost-effectivethanthe on-going cost of procuring services from DER.Interactions between DSOs, TSOsand market actors at different stages are depictedinFigure 10.

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Figure10DSO interactions with markets & TSO at different time framesTable1highlights the key features of each phase, broken down into the different layers : development &planning, operations, information exchangeandtechnical development.The subsequentsections of thereport discussthe active system management approach within the individual layersin detail.

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Network development(planning, connection &access)Fit and forget approach:everything solved at theplanning stageOnly operation approach:connectionwith norestrictions and solutionsatthe operations stageFit and forget approachActive capacity and lossmanagement throughcommercial interaction withmarket actorssellingflexibility servicesConnection and accesscriteria combined withoperation tools to manageDERFlexibility support from DSOto TSO and from TSO to DSOwhen requiredNew system services forDSOs arranged viacommercial ancillaryservices and grid codes.Network operationLow monitoring & control ofDG RES, often only bytheTSOMissing rules & services forDG contribution to quality ofservice, security ofsupply &firmness

Emergency generationcurtailment by DSOActive voltage controldistribution networks. Gridcodes for DG to meetconnection criteria and beable of voltage basedcontrol and reactive powercontributionInformationexchangeLittleinformation exchangefrom TSOs/DER to DSOs(small DER do not sendinformation)High-level informationexchange from TSOs/DERto DSOsStructured and organisedoff-line and where neededreal-time informationexchange (standardisedinterfaces with DERrequired)

Technical developmentNetworkLimited monitoring & controlcapabilities (usually only HV)Conventional SCADA for HVnetworkand DMS/OMS forMV and LVIncreased monitoring andcontrol at HV & MV viatelecommunicationsSCADA/DMS/OMSwith themeasurement of certainnew DG

Increased monitoring,simulation and control downto LV viatelecommunicationsAdvancedDistributionManagement Systems13forDSOs/SCADA andDistributionManagement System (DMS)DERDG often not prepared forpowerfactor controlStorage & EV not developedEnhanced DG protectionsystems/ invertersenablingvoltage & reactive powercontrolConfigurable settings: e.g.protection / fault ridethrough settings,voltagedroopPresence of storage & EVsTable1Three-Step Evolution of Distribution Systems in detail

13New SCADA and DMS/OMS could be integrated in a single system called Advance Distribution Management System(ADMS).

LayerPassiveDistribution networkRe-active distributionnetwork integrationActive distribution systemmanagement

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Data acquired within distribution network monitoring and information exchange with TSOs anddistributed energy resources (see sections 3.4 & 3.5)could be very beneficial in this respect.According to thetraditionalregulatory approachtoconnectionrequests analysiscurrently applied in most countries,thenetwork operatorperformsan individual analysisand provides an individual solution to each connection.The first connectionsmaymake use ofthe availablecapacity ofthe existent network.Butonce there is an increaseddemand for new DG connections in thesame areaandthe available network capacity is limitedthis approach is not always optimal from theoverall cost and network development perspective.14 (see Box3for Spanishexample).To rationalise the RES expansion and optimise the available energy resources,some Spanish regionscreated so-called"Evacuation Boards". Theyarecharacterised by a coordinated grid connection requestprocess. RES installation plans are deployed and coordinated between the administration, RES investorsand transmission and distribution system operators. Intheseevacuation boards the TSO or DSO donotreceive individual requests; they are collected by the Regional Administration and after a validation processsubmitted for an aggregated analysis tobe made together by the DSO&TSO. The positive impact of thenew networks for consumption (extra capacity for consumers) is also considered. In addition to the cost-sharing mechanism(proportionally to the capacity assigned to each RES project),the covenants for thedevelopment of such infrastructures contain the necessary guarantees, payment and execution terms.Benefits of this approach include overall minimised network development and project cost, reduction ofproject risks thanks to the possibility to correctlyanalyseboth the costs and timetables needed for thedifferent RES penetration scenarios,and reduced time for acquiring all necessary administrative permits..Whilst in some cases modificationsrequired by DSOs from TSOs or vice versa do not considerably affect the capabilities ofone or the othertomaintain their network performance, the impact may be substantial in other cases. For example, whentheHVor UHV(ultra high voltage)network is saturated, connection of generation totheMV network cannotbe planned without taking into account the conditions at HV network.An optimal network development isalso key tominimiselosses in the electrical system.Transmission or distribution network conditions whichrequire regular ( or conditional ) exch ange of informat ion betw een TSOs and DSOsshould be defined.Standard reciprocal data exchange arrangements about the expected development of generation/loadatthe different voltage levels and about the network reinforcements needed at the TSO level, notdirectly related to the lower voltage planning activities, should be put in place.14First requests for connection get the available capacity of the existent network at a low cost, but as they increasethey require more complex and expensive network development solutions. In countries where generators beargridconnection as well as grid reinforcement/extension costs(deep connection charges), this may make the individualprojects economically unviable. In countries where generators beargrid connection cost but not the gridreinforcement cost(shallow connection charges) and donot payanyuse of system charge, thosereinforcementnetwork costs are socialized.

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Coordinated planning as per the Irish Gate process (seeboxbelow), batch planning of DG connectionapplications at TSO and DSO level as appropriate, may see the most economical net cost of connection.Coordination betweentheTSO and DSO in Schleswig-Holstein (northern Germany),where 9,000 MW ofwindshouldbe connected by 2015,areanother examplein this respect.Up to 2003,applications to system operatorsfor connection of windwere processed sequentially. Since2004, following a moratorium on wind connections, DG is planned in Groups based on their networklocation and capacity and processed in batches known as Gates . This system was introduced to deal withthe massive number of applications.The queue for connection comprises both DSO and TSO applicants.Applications are processed by the system operator (TSO or DSO) most suited to their group connectionirrespective of which system operator they originally applied to. The connection method is determined bythe Least Cost Technically Acceptable (LCTA) method for the defined sub-group. The cost of the networkreinforcement for the group is shared by the different wind farms proportionally to their capacity.Connections below 500 MW have a different planning process and are treated as individuals with a quickerprocess,reflecting their connection generally being less onerous and costly.The regulator (with input fromboth system operators and wind industry) determines criteria for eligibility for inclusion of Gate . Thismethod facilitates large quantities of RES being processed in a structured manner and rationalisesallocation of scarce capacity. Transmission and distribution systems are developed in co-ordinated fashion. would encompassoptimisation of network capacity via improvedconsideration of DERs in network planning. The DSO ability to identify areas with possible overloadproblems well in advance as describedwithin the active approach is a precondition for this.iiDG developers could have a possibility to select firm or variable access contracts based on their ownbusiness plan.rights could be offered as adiscounted connection contract forgeneration customers, with pre-defined mechanisms for DG to reduce their output to a predefined limit ininfrequent situations, expected only for few hours per year.If only several hours of re-dispatching per yearare needed to limitpeaks of production and use network capacity more efficiently, those would be morethan offset by an additional DG output in all other hours due to a higher installed DG capacity up to acertain point where the cost of net losses and curtailed generation become relevant to justifynetworkreinforcement.A model example inFigure11illustrates thatlimiting peak power in-feed ofe.g.5% of the time would givean opportunity to connect 220% more DG.In these cases,generation operators should be incentivisedtochoosethis option, e.g. by reduced connection cost (cheaper but with limited guarantee of injection withina clearly defined framework) or other form of compensation. This could be executed either via directcontracts between DSOs and generators/load or indirectly between DSOs and aggregators who would pay ayearly option premium to DG/load and then offer flexibility to the DSO.

16

Figure11Variable access approach (Source: EWE Netz)Today, variable access is precluded by obligation to compensate generators for any energy they are notallowed deliver in many jurisdictions. As outlined above, curtailment is often possible only to deal withshort duration constraints; it is only temporary and automatically triggers grid adaptations such asreinforcement if they are deemed economically justifiable by the connected parties or DSO. A form ofvariable network accessforDG/RESexistse.g.in the UK (known as non-firm access). The conditions wherea DSO can issue a curtailment instruction are setout in a connection contract agreed at the time ofconnection in return for a lower cost of connection. For example, the feed-in management rules inGermany (see box below) define a flexibility obligation in form of a capped connection.The flexibility obligations,including the technical and regulatory possibility to be curtailed are spreadoverall production facilities above a certain capacity. The PV installation owner can choosetoinstall a technicalreceiver deviceallowing for feed-in reduction by the network operatorortoreduce the feed-in power to70% of the nominal power (installed power). In practice, thismeasureleads to the loss of about 5% ofenergy feed-in from PV but allows connecting more DG to the network (and thus overall increased DGproduction).The producers are compensated for lost production.This curtailment regimeenablesanoptimiseduse of the existing network, without jeopardising the business cases of new producers.Itapplies until the relevant grid development is made.Practical modalities of sucharrangements may differ from one country to another.In any case, thefollowing aspectswouldhave to be considered before implementation of a variableaccess scheme:iIt might be necessary to review the value of the discount from time to time, oritmight be possibleto have an auction giving a kind of merit order list (i.e. those who pay most for the grid use wouldbe curtailed less often) . A ri sk ofchanging conditions over time could be mitigated,e.g.byparticipation via aggregators.iDG developers should be provided with information on expected curtailment so that it can beincluded in the risk analysis and economic viability analysis of projects prior to investing in theseprojects. This shouldbe based on the best available information and analytical techniques, toensure that generation developerscan base their decision on an informed business plan.iEstablishment of procedures for assessing whenthe investment deferral is more cost-effective. Asexpectations change depending on the amount of RES already connected and the amount of RESthat will be connected later on, it might alsobenecessary to have insight under what conditionsthe DSO willundertakereinforcements, because additional RES might be addedat eachreinforcement(depending on the geographical possibilities). If RES developers have sufficient

17

transparency, they will takepossible interruptionsinto account,as well asthe value they need toearn back on a flexibility platform.iThe manner in which to curtail generators (pro rata, market based etc.) and the operational rulesfor the constraint location where more than one generator contribute to the constraintwould haveto be specified.Assessment of firm capacity is important for network operatorsto foresee how much generation cancontribute to peak consumption. A mechanism incentivising DG to generate or the consumption to stopconsuming when the peak on the network takes place would enable more efficient use of the existingdistribution assets and deferral of grid reinforcement, as illustrated inFigure12. Provision of certain firmcapacity would be rewardedasan extra service for the system.Remuneration for this service could bedetermined through an open commercial tendering process organised by DSOs,e.g. via a local auction fornecessary services (DG to bid certain amount of capacity reliably available).In any such cases, the party (DGor other commercial operator) deemed reliable and contracted to deliver certain firm capacity must beheld financially responsible for its delivery.

Figure12Extension of network capacity for peak load versus a load managementsolution (Source: EWE Netz)All in all, due to various generation mixes, distribution of generation over different voltage levels andgeographic distribution of the resources,aone-size-fits-all approach may not be adequate from the socialwelfare point of view. The option of giving network customers a choice between firm injection and higherconnection charges and non-firm injection and considerably lower connection charges should be assessedagainst other solutions.For proper integrationinto the network, distributed generation needs tofulfilminimum technical criteria:the equipment and its protective relays must be able to resist voltage dips and prevent islanding and thereshould be separate metering for production and consumption. DG should also bear the same costs as othergenerators, including adequate connection fees. DSOsmust know what is on-line when they are working toprevent accidents. Therefore, they shouldhave a possibility to verify compliance with requirements.Distributedgeneration should thus be registered with the DSO,and remote disconnection by the DSO toprevent damage to facilities of other clients whilemanoeuvringshould be technically possible underconditions definedbyregulation.To secure safe operation of the distribution grid, DSOsshould alsobeableto define control schemes and settings for generators connected to their grids, in coordination with theTSO where necessary in order to ensure compliance with overall system requirements.

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In order to make the best of the existing network,Practical modalities of these arrangements maydiffer from one country to another.Future production on DSO level should be taken intoconsideration when developingtheENTSO-E TenYear Network Development Plan and the relevant national plans.DSOs should be consultedaccordingly.Market-based in situations when it is proven to be more cost-effectivethanwaiting for provision of connection and access to the grid until any curtailment is ruled out.Distributed generation needs to fulfilminimum connectioncriteria.Distributed generationshould be incentivised to sell their production into the electricity market15.Aggregation of DG in form of so-called Virtual Power Plants (VPPs) or ofdistributed generation,flexibleloadsand possibly decentralised storageis expected to play an important role in facilitating access of smallcustomers to the market and addressing the uncertainty of availability and providing enhanced capability tomanagetherisk of not being able to meet the contracted scheduled output. The aggregator role couldalsobetaken up by electricity service companies(ESCO) or suppliers. The aggregator would provideaninterfacebetween DER and other market actors and system operators.In addition, DG should be obligedto meetscheduling, nomination and balancing obligationsas other power generators do,including payment ofbalancing charges. DGshould alsoberesponsible for their imbalances on equal terms with other BalancingResponsible Parties. It is highly beneficial for system stability and cost reduction if variable REStechnologiesare incentivised to reduce forecast errors and to minimise imbalances in the market and take up necessaryresponsibilities towards the system as other generation technologies do.16The network plays an important service role of supporting the market.Operational barriersmay arise,characterised by one or more violations of the physical, operational, or policy constraints under which thegrid operates in the normal state or undercontingency cases. They are transient associated with aspecified point in time. As such, they may be detected before or during the day-ahead, the hour-aheadmarkets or during real-time system operation.This means that they need adequate tools to operate their networks. In addition, networkusers need to actively participate in network usage optimisation.In this way, the possible abovementionedviolations can be eliminated.

15Today, small DG typically sells their electricity output at fixed prices to the TSO, an electricity supplier orother thirdparty market participant.Different economic for the production of electricity from RES andcombined heat and power (CHP) have been implemented at national level. Where fixed feed-in tariffs are in place,generators are exempted from market signals & prices. Support schemes shall be made more market-oriented, basedon production rather than investment.Support schemes which expose RES generators to market prices are morecompatible with well-functioning of electricity markets, thusproviding the correct price signals.16These obligations can mean new costs (whic h shou ld b e take n int o accoun t in adjustmen t o f th e supportmechanism) , bu t ca n als o mea n ne w source s o f revenues.SeeEURELECTRIC report May 2011.

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TheDSO is best placed to facilitate this mechanism as the dataneed to begathered at substation level and in-depth knowledge of the grid layout and its behaviour is required.Moreover, the DSO has a legal responsibility to ensure that such technical constraints are mitigated.The blue areainFigure13schematically outlines the stages in the electricity market in which the networkoperators do not interfere, but act as mere behind-the-scene facilitators. The green area depicts the systemservices that are to be administrated by network operators(for both transmission and distribution systemneeds). Table 1 providesamore detailed overview of such system services including their possibleform of delivery.Today, ancillary services are procured by the TSO, largely from large power producers, to manage thesystem as whole.

Figure13Market and network operations

17For definitions see Glossary.

System servicePurposeProvision by which typeof DERInformation exchangesForm of deliveryFirm capacitymanagement (long-term)DSO planning purposes;optimize of network capacityutilisationDG with a view tousing assets most efficientlyCHP, smallhydro,stochastic RES withintegrated storageAggregated demandproviders, DSMiDG outage programs and availabilities information (DG->DSO)iReal time generation output (DG->DSO)iReal time demand flexibility information (DER->DSO)iFirmness periods (DSO->DER)CommercialLosses compensationIncreased system efficiencyDSO, DG, demandcustomersiReal time load and network voltage or fault conditions (DSO->DSO)iReal time generation output (DG->DSO)iV, Q, pf setpoints (DSO->DG)iDemand reduction signals (DSO->Aggregators)CommercialSecurity congestionmanagement (short-term)Operate the grid within thesecurity standardsRES, CHP, distributedstorage, DSMiReal time load and network voltage or fault conditions (DSO-> DSO)iReal time generation output & loadflexibility (DG-> DSO)iReduced setpoint/ reduction signal (DSO-> DG)iDG outage programs and availabilities information (DG->DSO)Mandatory with compensation or bycommercial arrangement (non-firmaccess contracts)Anti-islanding operationAvoid unsafe,unbalanced andpoor quality distributionelectric islandsDG, storage, DSO (localnetwork controls)iLocal automatic signal generated in case of fault or triggering conditions-> all local DG, storage, network control pointsiLocal signal generator-> DSO SCADA or central control (an d loca l /regional control depot), notification signal by DSOMandatory without compensation (gridconnection rules defined in grid codes)20Frequency controlUnder extreme situations ofsystem strain, TSO to call uponDSO todeliver support DSOas a conduit but needs to seewhat is happeningDG & load to TSO via DSOiReal time active and reactive power flows information exchange at theT/D interface(DG & load->DSO->TSO)iLoad/generation to adapt (TSO->DSO->DG & load)Commercial (at TSO level)Islanding operationImprove continuity of supplywhen higher voltage source isunavailableDG, storage, DSO (localnetwork controls), DSMiReal time active and reactive power flows information exchange (DER->DSO)iV, P, Qsetpoints (DSO->DER)Mandatory with compensationDSO Voltage controlLocal supply quality securityand increasing amount of DGpower that could be injected inthe gridPV, Wind power, CHP,distributed storage, DSMiReactive requirement (amount andelectrical or geographical deliverylocation) (TSO-> DSO)iReal time load and network voltage or fault conditions (DSO-> DSO)iReal time generation output (DG-> DSO)iV, Q, pf setpoints (DSO-> DG)Mandatory without compensation tomaintain defined limitsfor distributionsystem stability. Commercial forpurposes beyond maintenance ofnetwork stability or outside the scopeof the customer s own connectionInformation exchangeOptimise DSO and TSO controlsupervision, and schedulingDER, TSOiTSO Real timeand off-line measurements and topology information(TSO-> DSO)iReal time generation output (DG->DSO)iDG and TSO outage programs and availabilities information (TSO->DSO).iDG generation forecasting (DG-> DSO-> TSO)Mandatory with compensationTable2NewSystem Servicesat Distribution Level

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To manage the operation of distribution systems, similarly to the usual practice in transmission networks,basic system states should be defined,e.g.within security standards or grid codes. A could be usedtodistinguishbetweensystemstatesand selecting appropriate type of actions(seeFigure14andthebox below):iThe (1)resultsfrom overlaying the stable operating points onanillustrative power-voltage curve for abstracted two-bus system. Itrepresents an area where thenetwork is secure and the power can flow either towards the consumer (becau se deman d isgreater than generation) or back to the system (when generation exceeds demand).If the system isat the, the market operates and the DSO has clear visibility of this.Theboundaries of this secure operating region depend on the physical characteristics of the networkand system dynamics.iillustratethe situationshampering secureoperation ofthedistribution system:voltage increaseand congestion(theplane has been rotated to align it with atime-varying load profile).i indicate alert network statesin which congestion management should beconducted in order to keep the gridfrom entering the red emergency state.When possibletheDSOactively engages with the market(DG or load)to procure flexibility to relieve grid constraints.Actions in this state must be specific and well defined by e.g. regulation or contracts and be temporary innature.Transparency is needed (each timeofoccurrenceand reasons); and analysisshould bemade ifindeed DG/load were not able to offer sufficient services.

Figure14Instability in thedistribution system

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Normal operating stateAlertstate DSO has an emerging congestion.DSO actively engages with the market (DGor load) to procure flexibility to relieve grid constraints:a)Via flexibility platform:a methodology has to be developed which links the offers ofaggregators withidentificationfor the location. For example, aggregators coulddivide theirVirtual Power Network capacity into local pools. A DSO can contract an aggregator fordelivering local generated electricity or load from the local capacity pool.This can befacilitated bythe DSO data hub.b)Directly:ADSO could contractthe customer (includin g D ER) in order to maxim ise theutilisation of distribution assets in planning and operational timescales where locallyneededwith ensuring transparency and non-discrimination for example via tenders.Unsecure operation Emergency casesIn strictly defined emergency cases,the DSOwould be able tomanage distributed renewablegeneration, to implement grid efficiency improvement measures, and to control the isolation andrestoration of outages.Thisisthe last measure taken by the DSO when every other optionhasfailed to restore system integrity.

18In these defined cases, theDSO could deviate from themerit order,but ex-post justification and compensation should be provided.This could be executedby pre-agreed contractsfor instance.The DSO should then pay the up regulating cost elsewhere in the system,and should remunerate the downward cost to the local generator thatis constrained off in his grid(including the missed income from the support scheme and the costsofkeepingbalancedposition).For definitions of CLS and DMS see glossary.

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Whenthe grid stability is at risk, DSOsshould be able to act physically to control and constrain off both localconsumption and production (as is already the case in some countries e.g. Germany or Sweden). Priorityaccess rules should not restrict network operators abilityto flexibly respond to emergency situations.TSOs should not act on any individual DERconnected to the distribution system.Any directorder fromtheTSO to DER embedded in distribution networks targeted to safeguard operation of thesystem will be executed by the DSO, not the TSO.Today, DSOs have no systems installed for acquiring data from DG of smaller size in particular. In somecases,theTSO receives information from DG in real time while DSOsdo nothave real-time access to thisinformation.There is not usually anoperationalexchange between the TSO and the DSO.19 At the transmission level, generators already send schedules to the TSO for system balancepurposesand togurantee that their realisation is technically possible. In systemswith high DG penetration, the DSO willneed information about DG forecast, schedules and active dispatch to improve their visibility and to assistwith real-time or close to real-time management ofthedistribution network including local networkconstraints.DSOsshould have managed access to communication and monitoring assets of DG to collectinformation that will be necessary for operation of their networks.The granularity ofthedata exchange willdepend on the size ofthegenerating unit.The necessary information should be then exchanged betweenthe DSO and the TSO (in both directions). DSOs should providetheTSO with information on active powerthattheTSO needs to facilitate secure systemoperation. DSOs operating sub-transmission networksmayalso require TSO information in real time.

Figure15Information Exchange Today and in the Future19Exchange between TSOs and DSOs operating HV networks exists in some countries.

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Generators and flexible loadsconnected to the distribution gridshould be able toalso provide theseancillary servicesfor system balancing and transmission system congestion management purposes.Aggregators may be able to achieve certain modificationsin the demand and in the generation of theconsumers and producers in their portfolio, in order to offer services to system operators.However, theissue that an area managed by an aggregator may not correspond to the distribution network responsibilityarea (forecasts and schedules are delivered at a portfolio level for a bidding zone)needs to be addressed.Inthese situations, the DSO needs to haveadequatevisibility to ensure that this activation does not impedesecurity of supply in its own network.Similarly, actions by the DSO to solve constraints could affect thesystem balance.(e.g. TSO asking fora modification whichwould violatedistributionsystemsecurity standards).Enhanced monitoring and control strategies for distribution networks will need to bedeployed(see section 2.4).As outlined earlier, voltage in the system needsto be maintained within a range defined by securitystandards.Voltage control is a system service managed by network operators in order to maintain voltagein their networks within limits and tominimisethe reactive power flows and consequently, technical losses.While generation/load balance is carried out at system level by the TSO, voltage control of the distributiongrid requires the involvement of the DSO. Voltage control has been traditionally done by transformers (using on and off load tap changersmoving reactive power) and capacitor banks that inject reactive powerinto the grid (seeFigure16).TheDSO fixes a setpoint and prepares scenarios/ranges for different voltages within which the voltage must bemaintained.

Figure16An illustrativeexampleof atraditional approach to voltagecontrol 25

iUsually power transformers with on-load tap changersiCapacitors frequently used to control the voltageiNo analogue values in secondary substations obtained in real time(typically analoguevalues only at MV feeders)iMV networks connected to HV through a power transformer with on-load tap changerCapacitors can be commonly found also in these substations to improve the power factoriVoltage setpointsspecified at MV substation busbarsiMV/LV transformersmay be fixed ratio (i.e. have not tap changers) orhaveoff-load tapchangers, manually controlled.Taps selected to compensate the effect of MV voltagedrops at LV levels (passive approach).iThese tap-changersoperate onlyafew timesduring transformers lifetime.iSometimes capacitorsare installedin consumer facilitiesto meet power factorregulationsiNew controllable MV/LV transformers are emerging but expensiveTable3Voltagecontrolincurrent distribution networksTwo technical considerations for voltage control in distribution networks include:With high DG penetration, active power becomes a significant driver for voltages changes in MV andLV networks (the kW-V effect is more significant than the kVAr-V effect). The lower the distributionvoltage level, the higher this effect.In MV and LV networks,theactive power effect may not be always neutralised by the reactivepower injections/withdrawals available in the system.Inhigh-voltage networks,DSOswill be able to maintain the voltage within the security standards.20Active power will not cause voltage deviation undernormal operation.On the other hand,atmedium and low voltage levels, active power changes due to DGfeed-in cause voltage rises (especially in cables).21Distributed generation changes voltage triangle designand as a result, both scenarios with and without DG have to be considered.As reactive powercannot be transportedover long distances and as many regions with high DG penetration(thus voltage control challenges) have no conventional sources of reactive power, managing voltage on alocal or sub-regional basis could be the most economically viable solution for the entire electricity system.For these purposes, theDSO should be able to sectionalise its networks, to activelyinteract with DG torequest supply voltage contrquotesdbs_dbs25.pdfusesText_31

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