System Operability Framework 2016
UK electricity transmission
NOVEMBER 2016 System Operability Framework November 2016
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Welcome to the 2016 System Operability Framework
We are in the midst of an In SOF 2016, we have focused on energy revolution. The economic providing you with greater insight landscape, developments in through a new approach that technology and consumer considers year-round balancing, behaviour are changing at an flexibility and operability needs. unprecedented rate, creating The results set the direction for more opportunities than ever developments across industry for the energy industry. rules, tools and assets. We will use this information to inform The 2016 System Operability a future operability strategy Framework (SOF), along with our that aims to facilitate solutions other system operator publications, from the whole industry. aims to encourage and inform debate, leading to changes that I hope that you find this document, ensure a secure, sustainable along with our other system and affordable energy future. operator publications, useful as a catalyst for wider debate. Your views, knowledge and insight For more information about all our have shaped the publication, helping publications, please see page 12. us to better understand the future of energy. Thank you for this valuable Please share your views with input over the past year. Now our us; you can find details of how 2016 analysis is complete, we have to contact us on our website: been able to look holistically at the www.nationalgrid.com/sof. results. Once again, the themes and messages have evolved Richard Smith according to your feedback and Head of Network Capability deeper insights from our analysis. (Electricity)
More than ever, we must address the flexibility and operability needs of the power system with efficient whole system solutions. This requires transparency of requirements and signals to bring competition to markets and drive down costs for the end consumer. System Operability Framework November 2016 02
Contents
Executive summary ...... 04 Whole system coordination ...... 142 1.1 What is the System Operability 5.1 Insights ...... 142 Framework? ...... 04 5.2 What is whole system coordination?.....143 1.2 Key messages ...... 06 5.3 Topic map ...... 144 1.3 Development of SOF 2016 ...... 07 5.4 Consequences and requirements ...... 145 1.4 How to use this document ...... 09 5.5 Assessments ...... 146 1.5 Future of Energy publications ...... 11 5.5.1 Visibility and coordination ...... 146 5.5.2 Active network management ...... 154 5.5.3 Voltage control from distributed energy resources ...... 161 5.5.4 Low frequency demand disconnection...... 168 5.5.5 Black Start ...... 171 Balancing and flexibility...... 14 2.1 Insights ...... 14 2.2 What is balancing and flexibility? ...... 15 2.3 Balancing ...... 18 2.4 Flexibility ...... 38 2.5 Balancing and operability: Conclusions and the way forward ...... 174 5–8 August 2016 ...... 53 2.6 Consequences and requirements ...... 57
Appendix 1 – Balancing methodology ...... 178 Appendix 2 – Glossary ...... 184 Frequency management ...... 60 3.1 Insights...... 60 3.2 What is frequency management? ...... 61 3.3 Topic map ...... 64 3.4 Consequences and requirements ...... 66 3.5 Assessments ...... 68 3.5.1 System inertia ...... 68 3.5.2 Fast active power injection ...... 73 3.5.3 Rate of change of frequency ...... 77 3.5.4 Frequency containment ...... 84
Voltage management ...... 102 4.1 Insights ...... 102 4.2 What is voltage management? ...... 103 4.3 Topic map ...... 106 4.4 Consequences and requirements ...... 108 4.5 Assessments ...... 111 4.5.1 System strength ...... 111 4.5.2 Voltage regulation ...... 116 4.5.3 Voltage dips and protection ...... 128 4.5.4 Voltage containment and recovery ...... 136 Chapter one 03 03 04
Executive summaryExecutive
one Chapter Chapter 2016 November Framework Operability System 2016 November Framework Operability System Chapter one Executive summary seminars andseminars direct communications. other contributions via our website, customer programme. Thank you for your and support year’s this of direction the discuss and to develop webinars of programme extended to an contributed year, 379 also This you of meet your needs. to better feedback, your on based develop, SOF to the approach assessments. We apply an evolutionary technical of aprogramme to inform experience standards andperformance operational combines it with stakeholder views, network and (FES) Scenarios Energy Future the from Our annual development process takes insight according to changing operational needs. assets and tools rules, industry of development of of the changing energy landscape. The purpose requirements that are needed to accommodate operability system identifies It publications. of suite Energy of Future the of part forms It operator. system GB the as capacity our is published annually by National Grid in The isWhat the System Framework Operability 1.1 System OperabilityFrameworkNovember2016 SOF System Framework Operability (SOF) 2016 is to set a clear direction for the the for direction 2016 aclear to set is , which continues to
How aspects of our system operability needs: three to inform information this applied have we as publication the throughout cases’ ‘flexibility different of anumber We explore scenario. energy future each for years ten next the over of credible generation and demand behaviours views year-round of aseries produced we how describes topic Flexibility and Balancing The before. ever than insight refined more provide to conduct more detailed assessments and us allowed has This Flexibility. and Balancing topic, anew of addition the with analysis our tomeaningful you. Notably, we have enhanced most and operation system future for important most are which to those topics of spectrum the to refine us helped year, have you last the Over When What do they change over time? over change they do are our requirements? our are do they arise? they do ? 04 Chapter one 05
the distribution companies enhance to our assessments in these areas. This topic describes the process which by developed we the future energy scenarios into half-hourly data. This allowed us explore to generation and demand flexibilityover the nextten years and provided insight into the range topics. other across requirements of distribution and This topic describes the characteristics and operational needs that govern the regulation and control of frequency. have updated We a number ofareas with our latest views including assessments of system inertia, have builtWe on previous regional analyses provide to greater insight across timescales. post-disturbance and disturbance steady-state, across enhanced be must capabilities where areas describes topic This the whole system ensure to effective and efficient operation in the future. support assessments with broadened our from networks across have We rate of change of frequency and frequency containment. frequency and frequency of change of rate This topic describes the characteristics and needs which govern the regulation and recovery of regional voltages the to appropriate level.
Frequency Management Whole System Coordination and Flexibility Balancing Voltage Voltage Management Table 1.1 Table SOF 2016 topics 2016 November Framework Operability System Chapter one Executive summary assessments, three key three assessments, messages emerge: our Throughout digitises. and decentralises decarbonises, system the as system energy affordable and secure asafe, to ensure weas work together and businesses who can address these requirements developers with dialogue increasing to an forward operator. We system GB look the as perspective our from requirements system out sets SOF The Key messages 1.2 System OperabilityFrameworkNovember2016 coordination system Whole management voltage and Frequency and flexibility Balancing the whole power system. power whole the across resources from participation with efficiently more addressed be can management voltage and Future requirements for energy balancing, frequency and visibility as the larger plant that they displace. performance same the for rewarded or provide to asked presently not are generators Small address this shortage. to required is resources network and energy approach which harnesses capabilities across to and voltage frequency A changes. holistic to of a shortage dynamic, immediate responses contributes Growing generation non-synchronous demand. flexible and storage energy as in tools balancing growth and technologies such by complemented this, accommodate to flexibly more operate to have will interconnectors other and generators Large 2016. SOF for assessed decade the throughout variability and size in increase flows Distributed generator outputs and interconnector
06 Chapter one
07
Nov 30 November 30 Launch event Oct Production Webinar Webinar Sep 2016 and the changes2016 we were 22/27 September 22/27 Post-assessment Post-assessment Aug SOF 379 attendees, representing over 100 100 over representing attendees, 379 In May, we outlinedIn May, our approach in a pre- with consulted We webinar. assessment of you on the133 topics include to in this year’s making reflect to your feedback.We followed with a mid-assessment webinar in where July, post-assessment a presented we September In preview of our findings webinarto 96 of you prior our to November launch event. by attended were sessions webinar Our consulted have We different organisations. with a spectrum of developers, manufacturers, service and academics owners, network providers from Great Britain and around the world. 150 of you were150 updated on our progress. Jul Webinar Webinar 21/25 July
Mid-assessment Mid-assessment
Jun Assessment 2016 May Webinar Webinar 19/24 May19/24 Pre-assessment Pre-assessment Apr Mar
Scoping 2015
SOF Feedback from from Feedback Feb 1.3 SOF of Development Stakeholder engagement Stakeholder engagement of enhanced programme An has been at the heart of our development process recognise this We year. that identify to we needs, operational future address and require input from across the sector which represents a broad range of views. Cross- ensure to essential is collaboration industry to found be can solutions economic that provide the best value for the end consumer. This philosophy has been reflected in our webinars open-invitation of programme with live question and answer sessions. Each webinar session was run twice for a total of six webinar events. Figure 1.1 Programme of SOF 2016 engagement 2016 November Framework Operability System Chapter one Executive summary publication of SOF the following feedback your We gathered did we You said, System OperabilityFrameworkNovember2016 wanted: you us You told document. year’s this of direction in your responses which have shaped the themes consistent of anumber were There the consultation process for SOF – potential solutions of appraisal and identification the Clearer requirements to facilitate – confidence greater with needs Deeper insight into medium-term operability – non-technical backgrounds audience from technical and abroader for messages Concise solution and flexibility assumptions. ,balancing to the according change needs those how and needed is it when needed, is what know We them. to fulfil solutions requirements without prescribing particular fundamental of aset outlined We have year. each across needs of granularity on the range and distribution greater with horizon time a ten-year on assessments our focused We have document’. this to use ‘How in outlined as readership, diverse amore for to cater analysis our of presentation and topics our of structure the changed We have 2015 and throughout
2016.
SOF SOF or security of supply. supply. of security or conduct assessment of energy margins tools operability other or assets prescribe solutions to codes, services, to pass coming scenarios energy future the of any of likelihood the conduct probabilistic analysis or assess of variable market conditions involve detailed commercial modelling solutions across codes, and assets. services of development the for direction the set topic each for systemdescribe requirements operability operational assumptions modelling on the basis of credible conduct balancing and flexibility scenarios energy future the of lens the through future the of views of arange assess 2016 doesn’t… does… 2016
08 Chapter one 09 2016, the following guide following the 2016, Technical readers Technical Suited for those seeking a understandingdetailed of with assessments specific background, additional discussion. and results chapter, the following guide indicates the the indicates guide following the chapter, content which is more suitable for all readers technical for suitable more is which that and readers in the other chapters. The Frequency Management topic is used in this example. As outlined this said, in year ‘You we did’, we have added another dimension our to analysis presentingby much of our information as annual distribution curves. Since this is a new SOF for development provides two examples of how read to these types of chart.
Insights management? frequency is What map Topic requirements and Consequences Assessments
andenables you quickly to access All readers All Suited for those seeking a the of understanding broad topic, the areas assessed, and high level outcomes of analysis. our We hopeWe this caters for a broader spectrum of audience than previous versions of the SOF We haveWe acted on your feedback make to wider a accessible to more publication our To backgrounds. diverse from audience support thisaim, we have restructured 1.4 document use this to How that recommend we While document. our all readers review our Balancing and Flexibility the information you are most interested in. Reader’s guide to SOF 2016 guide to SOF Reader’s Figure 1.2 2016 November Framework Operability System Chapter one Executive summary Example chart,distributioncurve(top),duration(bottom) Figure 1.3 System OperabilityFrameworkNovember2016 o p n e en e o e e o e r
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More focus More FES in five minutes is a world where economic economic where world a is 2016 or ‘ 2016 is a world where policy interventions and innovation are both ambitious and effective in reducing reducing in effective and ambitious both are innovation long-term on focus The emissions. gas greenhouse and prosperity of levels high goals, environmental the that ensure harmonisation European advanced achieved. is target reduction carbon 2050 Progression Slow Progression Slow as transition to ability society’s limit conditions quickly as desired to a renewable, low carbon world. businesses and consumers residential for Choices are restricted, yet a range of new technologies and progress some in results This develop. policies towards decarbonisation but at a slower pace like. would society than Gone Green Gone Green Gone are summarised below; however, we encourage we however, below; summarised are you read to the FES to 2050. useWe these scenarios informto the network planning are we investments the and analysis benefitto our customers.You will see this throughout scenarios referenced these document, as well as the other Future of Energy Energy Scenarios Future 2016 The publications. gas, are based on the energy trilemma (security and affordability) sustainability and supply, of out projections demand and supply provide further insight. for summary document Green ambition Green
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Less money money Less More money money More Future Energy Scenarios: http://fes.nationalgrid.com/ Scenarios: Energy Future 1 National Grid has an important role play to in industry our across debate energy the leading and working with you make to sure that we secure our shared energy future. As the system operator, we are perfectly placed as an enabler, informer and facilitator. The publications that we produce are intended be to a catalyst for debate, change. and decision making The starting point for our Future of Energy Energy Scenarios Future the is publications (FES) 1.5 Energy of publications Future 2016 November Framework Operability System Figure 1.4 from stakeholders across the energy industry. industry. energy the across stakeholders from and electricity both cover which scenarios, The The 2016 Future Energy Scenarios Chapter one Executive summary 6 5 4 3 2 8 7 System OperabilityFrameworkNovember2016 Future Operability Planning (FOP) Planning Operability Future years. ten next the over required be will that decisions development network and requirements capability the of view our provides also It on. working currently are we system. is available on the gas national transmission capacity exit and entry where and what detail in Gas Ten Year Statement (GTYS) TenGas Year Statement the following documents. transmission capability and operability through electricity and gas of view long-term our We build by consultation. planning activities and are complemented designed to and support inform business are publications winter. These or summer supply andelectricity demand for the coming and gas of assessment an to provide season now and in the future. future. the in and now system gas secure and safe aresilient, maintain to continue we sure to make helps It making. ourmodify operational processes and decision to us lead may turn, in This, signals. market and to you respond we way the to change a need FOP The processes. established and operation affect these how considers It system. the operability of the gas national transmission how describes changing requirements affect Report Outlook Report transmission, we produce the Summer electricity and gas of views short-term For Statement/ Electricity Ten Year Statement: http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/Electricity-Ten-Year- Future Planning: Operability http://www.nationalgrid.com/gfop Gas Ten Year Statement: http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/Gas-Ten-Year-Statement/ Winter Outlook Report: http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/FES/Winter-Outlook Summer Outlook Report: http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/FES/summer-outlook/ Framework/ System Operability Framework: http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/System-Operability- Assessment/ Network Options Assessment: http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/Network-Options- 3 GTYS . We publish them ahead of each each of ahead them . We publish provides an update on projects projects on update an provides 2 and Winter and Outlook 4 describes describes highlights highlights 5
Network Options Assessment (NOA) Options (NOA) Assessment Network transmission network, please consider reading these requirements across the GB electricity recommendations that we believe will meet investment network the about out finding in interested are you If years. ten next the over the GB National Electricity Transmission System models and highlights the on capacity shortfalls to network Scenarios Energy Future the applies energy and industry inform debate. the across information to share views your To help shape these publications, we seek needs. operability system to address assets and tools rules, industry of development for direction changes in operational requirements that set the operability of GB electricity networks. It describes future the to examine Scenarios Energy Future System Framework Operability (SOF) across the GB electricity transmission network. recommendations that we believe will meet them in on the future capacity requirements described Electricity Ten Year Statement (ETYS) Ten Year Statement Electricity ETYS to present the network investment investment network the to present . 8
uses the the uses 7 builds builds 6
12 Chapter two
13 13 14
Balancing and flexibility two Chapter Chapter 2016 November Framework Operability System 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing Insights 2.1 System OperabilityFrameworkNovember2016 lowest valuedecreases overthedecade. experienced formore oftheyearand Low transmissionsystemdemandsare with weather-dependent outputgrows. more variableasdistributedgeneration Transmission systemdemandbecomes and howtheychangeovertime. requirements: howmuch,often to provide greater insightintooperability other assessmentsandallowsSOF2016 transmission system.Itfacilitatesthe generation ontheoperationof interconnection anddistributed highlights theimpactofgrowth in Our balancingandflexibilityassessment
efficient solutions. reactive powerrequirements todetermine considered holisticallyacross activeand Flexibility andoperabilitymustbe throughout theday. desynchronising andloadfollowing more flexibleintermsofsynchronising, Users ofthepowersystemmustbecome and interconnectors. needed from smallgenerators,demand by smallgenerators.More flexibilityis when large generatorsare displaced required toensure sufficientflexibility Additional balancingactionsare
14 Chapter two 15 The generator dispatcher selects which selects dispatcher generator The generators need run to meet to those demand profiles, while taking into account a flexibility ensures It operation. system for requirement that there is sufficient generationto meet demand and that this generation has the in output decrease or increase to capability short timescales. This is account to for demand forecast generation renewable errors, forecast breakdown. generation potential and errors, balancing the of actions the simulates This centre. control national the in engineers Flexibility periods settlement 48 in operates market The generation period, half-hour each In day. per must equal demand. It is the system operator’s role resolve to differences between them and what actually happens in real-time. It also has shape to the delivery of power minute- Balancing the of use the through by-minute Mechanism (BM).
,
, combined, 1 to project to a daily demand profile FES Demand profiler. Generator dispatcher. Generator
An ordered list of generators, sorted by the marginal cost of generation. with operational data and a simulation simulation a and data operational with of European interconnector flows. components: main two has model The 1. 2. The demand profiler uses historical the for each day of the next decade. operational data together with data from from data with together data operational 1 Balancing is the activity of matching supply matching activity of the is Balancing 2.2 balancing What is and flexibility? with demand. This chapter has two parts: The first is about the modelling approach that we have used provide to greater insight second the operability requirements; into part is an assessment of changing flexibility decade. coming the over requirements Balancing In order assess to operability throughout each we required year, a credible dispatch future of projection a against generation of demand profiles.To do this, we developed a technique that uses data from the FES 2016 November Framework Operability System such as installed capacities of generators generators of capacities installed as such order merit anticipated and Chapter two Balancing and flexibility and Balancing submit technical parameters such as their also They output. their adjusting for prices Balancing Unit Mechanism (BMU), submits in the Balancing Mechanism, known as a participant ‘gate of closure’, each time the By The BalancingMechanism Figure 2.1 Figure 2.1 3 2 System OperabilityFrameworkNovember2016 real-time, the system operator has between and ‘gate closure’ Between timescales. energy market transitions into system operation There are additional mechanisms for generators that require more than 90 minutes’ notice. minutes’ 90 than more require that generators for mechanisms additional are There Adapted from: https://www.nao.org.uk/wp-content/uploads/2014/05/Electricity-Balancing-Services.pdf ear 2 describes how the activity of the the of activity the how describes
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16 Chapter two 17 to manageto other system parameters such as voltage. There are also a number of ‘reserve’ operator system the allow services, which accessto extra generation or demand at services, which ‘response’ and short notice, imbalances. second-by-second counteract e erat e a
re a t t e t t a Figure 2.2 balancing actions Example of system operator The system operator’s role is optimise to meets generation that so adjust to units which demand, as shown in Figure This 2.2. must way, economical most the in achieved be accounting for considerations such as flow requirements and network the on constraints 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing SOF 2016analysisbreadth Figure 2.3 only however, it conditions, demand extreme the of analysis detailed and focused for transmission demands. This approach allowed minimum summer and peak winter year: the of been assessed at the most challenging points In the past, system operability has typically Background requirements. systemassess operability to abasis forms and years ten next over the operation Year-round modelling provides greater insight into system Balancing 2.3 System OperabilityFrameworkNovember2016
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, we generally use and only use the other cases Reserve from transmission Reserve from conventional plant 100% 50% 0% A B C Throughout the SOF the Throughout B case flexibility where relevant for comparison. Presently, the majority of the flexibility requirement is satisfiedby conventional BMUs. Most of this some with generation thermal conventional is flexibility providedby storage andby non- operating Today’s generation. synchronous between somewhere therefore is condition flexibility case A andflexibility case B It is expected become to more like flexibility case B as access flexibility to from new and existing sources improves. An example of a recent development in this area is the new their lower marginal cost of generation, generation, of cost marginal lower their will be more heavily loaded or at full output. The part-loaded generators must have the output their decrease or increase to capability operator system the from instruction an following frequency to response in automatically or deviation, if they are selecteddo to so. Since the flexibility requirement causes units from running at full load at peak demand, we used sensitivity studies test to some transmission plant to run out of merit of out run to plant transmission some at periods of low demand and prevents of sources alternative using effect of the flexibility. The other sources are not specified, but they could include flexible demand, others. among storage, and interconnectors, These are our ‘flexibility They cases’. describe the proportion of the reserve requirement that plant conventional part-loaded by provided is
, provides GW, GW, GW andGW 4 GW andGW 5.5 2016 provides 2016 this level of insight into GW. Typically, this Typically, reserveGW. is spread Reserve or ‘upwards regulating reserve’ describes the abilitynegative to increase reserve supply or ‘downwards or reduce regulating demand within reserve’ four hours, is the opposite and – the ability to reduce generation or increase demand Hydro, biomass, gas (CCGT), coal, gas (OCGT) and gas oil are included within four hours. four within the system operator with the flexibility needed reactto unforeseen to events, such as unit breakdowns and uncertainty in the demand forecasts. generation and The amount of reserve required depends on throughout varies and conditions system the Thethe day. approximate range of positive reserve is between 3.6 and negative reserve is between 2 3.5 dispatchable part-loaded of number a across the down lower usually are which generators, units. operational other the than order merit The units higher up the merit due order, to 4 5 SOF operability for every year over the next decade. wantedWe not only measure to the size of a often how understand also but requirement, it arisesand for how long it exists. This allows on based assessed better be to solutions for how much capability is needed and how often required. is it developedWe an approach that combines historical data, projections from the FES balancing of representation simple a and half-hourly a created We requirements. demand profile for each overday the next according generation dispatched and decade overlaying By approach. based merit-order a to dispatch, this onto requirements balancing we then adjusted the plant which was running according set a to of sensitivities which we have called ‘flexibility These cases’. are further explained below. If you are interested in reading please detail, in process dispatch the about refer the to Balancing Methodology appendix. cases Flexibility allow theTo system operator match to supply and demand, access extra to This reserve, positive and negative 2016 November Framework Operability System hours few a required is resources balancing ‘reserve’. call we which real-time, of ahead Chapter two Balancing and flexibility and Balancing ‘Demand Turn Up’ service ‘Demand 6 System OperabilityFrameworkNovember2016 generation. solar by distributed suppressed not the distribution of transmission demand if it was output of solar generation. This is equivalent to show the distribution of the same, plus the transmission demand while the dashed lines years. The solid lines show the distribution of the solid and dashed lines in respective between difference by the shown is This shape of the demand distribution curves. in distributed solar generation affects the growth the how shows 2.4 also Figure which suppresses transmission demand. generation, distributed of growth the and demand underlying in trends the of a result 2.4. is This Figure in shown as decade, the over scenarios all in declines maximum, and minimum both demand, Transmission Demand Results has been assessed. that flexibility of spectrum the and behaviours market pure to demonstrate included is which C case flexibility in modelled as system the operate to reserve of sources other insufficient Demand Turn Up: http://www2.nationalgrid.com/UK/Services/Balancing-services/Reserve-services/Demand-Turn-Up 6 . Presently there are are there . Presently
, always occur during the hours of darkness. they because demands transmission maximum in distributed solar generation has no effect on Growth magnitude. by aremarkable reduce indicates that transmission demands typical 30 between maximum alocal cause otherwise would that demands of suppression frequent the is second The the relevant pair of solid and dashed lines. between adifference not is there and 03:00 transmission demand occurs at about minimum daily the effect, this Without left-hand tail of the relevant distributions. the in 2.4 agrowth as Figure in shown are levels of minimum transmission demand new These minimum. daily of point new the becomes it that extent an to such suppressed to be day the of middle the in demand Growth of solar generation causes transmission distributions at low transmission demands. the of shape the is feature notable first The 35 GW and GW, which GW, which
20 Chapter two 21 Gone Green Slow Progression tra e a tr te ar tr te e a tra tra e a tr te ar No Progression Consumer Power
tra e a tra tra e a Figure 2.4 demand by scenario Distribution of transmission 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing features include: 2016/17 to the notable the Referring profile, for each scenario. Transmission demandprofiles,spring Figure 2.5 April in Monday first the for profile the how shows 2.5 Figure profiles. demand transmission The distributions are informed by daily Demand profiles 9 8 7 System OperabilityFrameworkNovember2016 For more information on the dispatch assumptions, please refer to the Balancing Methodology appendix, page 178 page appendix, Methodology Balancing tothe refer please assumptions, dispatch the on information more For GMT. Kingdom, United Warwick, for are times sunset All Note that all times, including those used in graphs, are in GMT. at 19:00 (sunset at 18:45 at 19:00at (sunset demand 16:00, peak with approximately at starts pick-up demand evening an solar generation to distributed due day the of middle the in a prolonged demand suppression occurs hours from 03:00 o a 13 7
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2020/21 r re demand profile. demand by the more variable shape of the transmission distributed wind and solar generation is shown of output 2012). variable (26 March more The 2016/17 2011) from (4 April example the than changeable wind and solar conditions 2025/26 uses a reference day areference 2025/26 uses from example The evident. also is generation the intermittency in output from distributed addition to the magnitude of the suppression, by 2025/26. day In the of middle the in suppression demand by the shown as decade, the over increases scenarios between growth The variance in distributed solar generation C er er C er 2025/26 9 which had more
22 Chapter two
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morning pick-up 5 of to solar distributed from output high suppresses demand 7 by o the evening peak occurs at 20:00 morning peak value peak morning 19:45). at (sunset minimum demand of 16.8 Approximate values. Approximate 10 Figure 2.6 demand profiles, summer minimum Transmission The profiles for the days of summer minimum transmission demand are shown in Figure 2.6. on occurs usually demand minimum Summer a Sunday, although Progression for No Progression Slow profile, which Theoccurs 2016/17 2020/21. on features following the has August, in Sunday a 2016 November Framework Operability System there are twoBy 2020/21, notable changes theto profiles. The first is that in the scenarios generation solar distributed greatest the with growth, early hours of the morning, but in this example occurs on a Monday in September. This differs Progression the time of the minimum has moved from the early hours the to middle The of the day. second is that Progression in Slow Chapter two Balancing and flexibility and Balancing Transmission demandprofiles,wintermaximum Figure 2.7 include: aWednesday, on occurs which 2016/17 the of features The profile, generation. solar distributed in growth by the driven not is it because year every in scenario every for date same the on occurs demand maximum winter in Figure 2.7. Unlike summer minimum demand, shown are demand transmission maximum winter the of days the for profiles The System OperabilityFrameworkNovember2016 (sunset at 14:55). 51.5 of demand maximum evening pick-up of 2.6 the until flat relatively remains demand morning pick-up of 18.5 of pick-up morning o 29.3 of demand minimum e ree
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r re Consumer Power 100 and 2016/17, in scenarios 73 to between pick-up increases from 56 Table in 2.1. demand in detailed change The in magnitude over a smaller timespan, as leads to the morning pick-up increasing 48.8 44.8 to between reduces demand maximum the decade, the of course the Over to between 15.3 to between GW, while the minimum demand falls falls demand minimum the GW, while MW/minute ( MW/minute GW and 16.4GW and respectively). C er er C er No Progression
MW/minute in all 2025/26 GW. This GW. This GW and GW and MW/minute MW/minute and and
24 Chapter two 25 73 85 100 80 Demand Demand ramp rate (MW/mn) 2025/26 5:00 4:30 3:30 4:30 Duration (h:mm) 21.9 17.9 21.0 21.6 Pick-up (GW) 56 Demand Demand ramp rate (MW/mn) 2016/17 5:30 Duration (h:mm) 18.5 Pick-up (GW)
Consumer Power Consumer No Progression No Green Gone Slow ProgressionSlow Table 2.1 Table peak morning pick-up Winter 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing Generation dispatch,2016/17spring,GoneGreen Figure 2.8 that services or actions represents This resource. balancing’ ‘other to ageneric allocated is demand unsatisfied of remainder the ashortfall, still is there subsequently If dispatched. are units storage satisfied, been yet not has demand and dispatched been has coal and gas oil. If the available generation conventional generation: hydro, biomass, gas, of types various the before shown, then are system transmission to the connected are that outputs of wind, solar and marine generation above the nuclear output. The relatively small value apositive as shown is it importing, is GB into flow interconnector day. net the If whole generation runs at baseload throughout the Gone Green 2016/17,April in Monday first the is example This profile. demand atransmission meet Figure 2.8 shows generation dispatched to Generation 11 11 System OperabilityFrameworkNovember2016 Minimum output is assumed to be 55% of each unit’s capacity. unit’s each 55% of to be assumed is output Minimum o Transmission flexibility ter e t r ear
. From the bottom up, nuclear up, nuclear bottom the . From
r ar e ar ra e a
C a a a maximum or minimum or maximum to their moved all were they if time that at reached by the conventional units running be could that range maximum the is It in real-time from conventional BMUs. available is that flexibility the of boundaries transmission demand line mark the The dashed lines above and below the services. demand flexible or as behaviour changes due to price signals such modelling, the of scope of out are required to balance the system. the to balance required demand and subsequently the generation transmission on effect its clear to make transmission generation, but it is illustrated the as way same the in dispatched not is transmission demand line. This generation Distributed generation is overlaid above the ther a a t ra e a 11 output. t t
ther ar
26 Chapter two 27
ar ther t t because it is 13 . 14 a a t ra e a a ther acting like demand (importing power from (importing demand power like acting the network into storage) it is shown as negative. Note that storage is not generally used as part of the dispatch factored into the flexibility cases. Conventional BMUs continue run to only meet to the flexibility requirement and ensure to that the nuclear units are not deloaded. The transmission demand line diverges from generation distributed boundary between the of times during generation centralised and export. It represents the level of transmission demand within GB, excluding flows into interconnectors or storage a a C a .
GW toGW ra e a ra ar ar e r GW, that it requiresGW, the . When the flow across all
12
ear ter e t r flexibility Transmission o See the appendix for more information on the balancing methodology and use of storage technology. Interconnectors are used as the main balancing item sources. of variety in a the from modelling. found be would modelling the In reality, the flexibility that the interconnectors provide in This definition of demand is sometimes known strictly ‘nationalas demand’. 12 13 14 Figure 2.9 Consumer Power Generation dispatch example, summer, achieve balance achieve Generation by scenario by Generation Summer for dispatch generation the shows 2.9 Figure the day of thesummer minimum transmission demand in Power June Consumer 2025/26 The output from distributed solar generation generation solar distributed from output The is so great, up 25 to interconnectors export to up 8.7 to 2016 November Framework Operability System like a generator (exporting power the to when but positive, as shown is it network) of the interconnectors is a net export, this is graphs. the on generation negative as shown The same is true for storage – when acting Chapter two
2025 2020 2016 Balancing and flexibility and Balancing Generation dispatch,summerminimumdemand Figure 2.10 years later In them. between interaction the and of both interconnection and distributed solar, 2016/17, growth 2025/26. the 2020/21 Note and in scenarios the of each in manifest minimum 2.10 summer of Figure days the how shows Each graph covers24hours frommidnight System OperabilityFrameworkNovember2016
Consumer Power generators were more flexible in their operation. their in flexible more were generators nuclear of fleet existing the if years earlier in constraint. This constraint could be alleviated which alleviates the downwards flexibility the capacity of nuclear generation reduces, Gone Green 28
Chapter two
2025 2016 2020
29 ar ther t t a a t ra e a a ther No Progression
a a C a ra e a ra ar ar e r
Slow Progression
ter e t r flexibility Transmission ear
o Each graph covers 24 hours from midnight 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing o Generation dispatchexample,winter2020/21,SlowProgression Figure 2.11 are Europe mainland from GB into imports Progression 2020/21 Slow for December in demand transmission maximum winter the of day the for Figure 2.11 shows the generation dispatch Winter System OperabilityFrameworkNovember2016 Transmission flexibility ter e t r ear
. In this example, interconnector interconnector example, this . In
ar e ar r ra e a
C a a a sources of flexibility. of sources other or measures demand-side through managed be would balancing’, ‘other as represented residual, The export. storage and generation dispatchable is as maximised, ther a a t ra e a t t ther ar
30 Chapter two 31 2016 November Framework Operability System Chapter two
2025 2020 2016 Balancing and flexibility and Balancing Each graph covers24hours frommidnight Generation dispatch,winterpeakdemand Figure 2.12 reduces plant coal of availability the how Note 2016/17, in scenarios 2025/26. 2020/21 and the of each in manifest demand maximum 2.12Figure winter of days the how shows System OperabilityFrameworkNovember2016
Consumer Power interconnector capacity. growth in demand-side measures and subsequent the and years five first the in even Gone Green 32
Chapter two
2025 2016 2020
33 ar ther t t a a t ra e a a ther No Progression
a a C a ra e a ra ar ar e r
Slow Progression
ter e t r flexibility Transmission ear
o Each graph covers 24 hours from midnight 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing reduced and, if necessary, reversed. necessary, if and, reduced across interconnectors to mainland Europe are flows the capability, this to provide units these requirement alone. To create enough room for flexibility the than greater much is units these of -15%/+30%.of output the that means This flexibility allows 70% point the set so demand) downwards (decrease generation or increase the of size the twice approximately is demand) requirement (increase generation or decrease flexibility upwards Typically, the capacity. 70% their of approximately is that point a set output, the part-loaded units run typically at decrease or to increase facility the includes requirement flexibility the since Furthermore, capacity. unit’s 55% to be each of assumed output, of level minimum their than lower no conventional BMUs. These units must run part-loaded on held is requirement flexibility Flexibility case A dispatch. the affect cases flexibility B case flexibility use all examples preceding The case flexibility by Generation System OperabilityFrameworkNovember2016 . Figure 2.13 shows how the alternative 2.13. Figure alternative the how shows requires that 100% of the 100% the of that requires dispatch has, not what the requirement is. requirement the what not has, dispatch the flexibility much how show lines dashed the that Note modelling. the of scope the within not is technologies across flexibility of distribution exact the but interconnectors, or assets storage demand, flexible include could flexibility of sources These units. conventional the of set-point 70% the capacity of unlike on units with a neutral operating position, held is flexibility the of all where a condition conventional BMUs. This case represents part-loaded on held be to flexibility any require not Cdoes case flexibility comparison, In
34 Chapter two
35 ar ther t t Flexibility case C a a t ra e a a ther
a a C a ra e a ra ar ar e r
Flexibility case A
Transmission flexibility Transmission ear ter e t r
o Figure 2.13 flexibility cases A and CGone Green flexibility cases A and, summer 2020/21, Generation dispatch for 2016 November Framework Operability System Chapter two
C B A Balancing and flexibility and Balancing Each graph covers24hours frommidnight Generation dispatchbyflexibilitycase,summerminimumdemand Figure 2.14 requirement on conventional BMUs at flexibility the of more holding of effect the Note in 2020/21, scenarios. all cases for flexibility the of each in manifest demand minimum 2.14Figure summer of days the how shows System OperabilityFrameworkNovember2016
Consumer Power sourced from elsewhere. the part-loaded conventional plant, it could be for room to create resource balancing main the interconnectors are used in the modelling as periods of low demand. Recall that while the Gone Green 36
Chapter two
C A B
37 ar ther t t a a t ra e a a ther No Progression
a a C a ra e a ra ar ar e r
Slow Progression
ter e t r flexibility Transmission ear
o Each graph covers 24 hours from midnight 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing generation grows, which displaces the requirement. As the capacity of distributed avisibility with contracted been has service asystem where or emergency an of case the in except output, their to adjust them to instruct ability the have not does operator system the that is second The real-time. in or advance in either operator, system the to visible not is generators these of majority the of output the that is first The ways. main transmission-connected generation in two Distributed generation differs from to adapt. need therefore will units, to those generation and the capabilities inherent dependent on transmission-connected mostly are which system, the to balancing approaches Existing systems. to external distributed generation and interconnection increased towards moves mix generation The Balancing assessment shows that the and their technical characteristics. depend on the energy resources available capabilities Both output. its change can fleet generation the which at rate maximum the is This capability. rate ramp is second The or decrease output to follow demand. generators which are running to increase the of capability total the is This capability. is upwards and downwards regulation first The capabilities. by two determined is balance between generation and demand to maintain ability operator’s system The Background risks. security system cause powernot flowsdo interconnector in changes rapid that other sources are realised. Action is requiredto ensure unless flexible increasingly to be required be will which will displace generation, transmission the remainder of inGrowth interconnection and distributed generation Flexibility 2.4 System OperabilityFrameworkNovember2016
changing their flow simultaneously. flow their changing the likelihood of multiple interconnectors throughout the day. This quantisation increases points time fixed at occur movements interconnector blocks, time 30-minute fixed in traded is interconnector each across power to transfer capacity Since opportunity. earliest the at change will interconnector the across flow the change, conditions market When area. price higher to the area price lower the from flows generally Power connects. it to which markets the between price power in interconnector is governed by the difference each across flow power of direction The system. smaller to the risk amaterial is this Europe, to mainland GB as such system, large to a connected system asmall of case the In demand. and supply in imbalance to alarge appropriately managed, could also rapidly lead not if capability, same The required. if support, systems to which they connect with fast very the to provide capability the interconnectors 50 of excess in a rate at it across flow power the to vary able is operational risks. An individual interconnector improved technical capabilities and increased both presents interconnection of Growth fornecessary balancing in real-time. forecast requirements and access the services to ability operator’s system the impact will transmission system, these characteristics conventional generation connected to the MW/s. This gives gives MW/s. This
38
Chapter two
39
Gone Green Slow Progression t t t t MW/minute. This occurs as a result of the of time with changes of demand close to in Figure 2.15 by the reduction in the proportion the in reduction the by 2.15 Figure in 0 generation, distributed variable of growth output the generation, solar and wind as such be to demand transmission causes which of more variable. Note that the method smoothes for endure which demand in changes out lessthan 30 minutes and therefore will underestimate the maximum ramp rates.
. This is shown No Progression
Consumer Power t t t t and Green Gone Figure 2.15 transmission demand Annual distribution of half-hourly variation in Results the compare assessments following The change in generation or demand between each settlement period, averaged to a a to averaged period, settlement each per-minute rate. Demand demand transmission of variability The increases over the decade in all scenarios; the largest changes occur in Consumer Power 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing changes in the distributions in Figure 2.15. the drives that interaction this is It period. same the over constant relatively remains 2017, in day the for time this demand During line. dashed white by the 19:00,and marked 12:3007:00 12:30 between and pick-up and generation, causing a drop-off between solar by distributed suppressed 2025 is in day the for profile demand the how shows the periods of darkness. The comparison aligning by comparison for profiles two the by 3.4 down scaled been has 2017from day the for profile The generation. with different capacities of distributed solar Effect ofsolargenerationontransmissiondemandprofileandflexibilityrequirement Figure 2.16 days 2.16, similar two Figure shows which in shown is profile demand transmission the The impact of distributed solar generation on 15 15 System OperabilityFrameworkNovember2016 They share the same reference day, 5 April 2011. Both are from the Gone Green the 2011. from are day, 5April Both reference same the share They
o pr Offline on both days both on Offline
pr GW to calibrate GW to calibrate Online on both days both on Online
15
increase run in marginal short cost. to an lead could This reliability. to lower leads on thermal power stations in particular, which stresses greater imparts and units these of efficiency the reduces shifting’ ‘two of regime This 16½ of hours. aperiod for evening, until morning from run otherwise have would it when hours, six approximately for day the of middle 500 A generic transmission connected generator is shown. demand suppression on an individual Furthermore, the effect of the transmission Online in 2017 and offline in 2025 in 2017 in offline and Online scenario. MW unit is shown offline in the the in offline shown is unit MW 40 Chapter two 41
and negative values correspond to downward downward to correspond values negative and rates. ramp The method evaluates initial ramp rate rate ramp initial evaluates method The the at position units’ the given capability does It period. settlement the of beginning not assess for how long that ramp rate could be sustained. Furthermore, the ramp rate the that assuming capability calculated is system operator could instruct all online units simultaneously. Existing operational systems restrict the number of most types of instruction instruction one with minutes, two every one to required for each BMU. Instructions can be issued a short time in advance when there is sufficient certainty in the requirements which constraint. this alleviate to helps The distributions of residual ramp rate capability Positive are shown in Figure 2.17. values correspond upward to ramp rates
. 17 available. It excludes nuclear 16 Ability to reduce generation down to their stable export limitapproximately (SEL) or design minimum of 55% the unit operating capacity level for a conventional (DMOL), usually generator. For more information, please refer to the Balancing Methodology appendix, page 178. in the Balancing assessment Balancing the in generators, which are assumed be to inflexible which units, storage and assessment, this for are usually excluded from the dispatch stack 16 17 Generation As the number of running transmission- they as drops units generating connected are displaced by distributed generation, so so generation, distributed by displaced are does the total ramp rate capability available theto system operator. The residual ramp rate capability is the maximum rate at which dispatchable its reduce or increase could generation output, less the coincident rate of change in demand. It is a measure of the ability of further to respond to generation running the changes in demand or the output of other generators, for example due a breakdown to or a change in interconnector flows. dispatchable as counted are which units The in this context are the BMUswhich are running at the time and have headroom or footroom 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing Annual distributionsoftheresidualrampratecapability Figure 2.17 System OperabilityFrameworkNovember2016 t t t t t Consumer Power
No Progression t t t t t Slow Progression Gone Green 42 Chapter two 43
Gone Green Slow Progression t t t t the downwards ramp rate is similarly restricted. Figure 2.18 shows how the flexibilityFigure 2.18 case affects the distribution of ramp rate capability. When the number of part-loaded units is of proportion the reducing by reduced, flexibility providedby conventional generators, the upwards ramp rate in particular is greatly restricted. time At of lower demands, when the flexibility requirement requires a minimum amount of downwards flexibility,
C No Progression
Consumer Power t t t t e t a e Figure 2.18 rate by flexibility case, 2020/21 Annual distributions of residual generation ramp The upwards ramp rate capability is restricted theby number of part-loaded units as a result of the system operator’s flexibility requirement. The downwards ramp rate capability is restricted the by number of units running above stable export limit. This means that the capability available is high at times of high generators many are there because demand running. When demand this is low, capability is substantially reduced. substantially is 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing Annual distributionofresidualgenerationramprate,summervs.winter, GoneGreen2020/21 Figure 2.19 frequently, occurs low. This also is running units of number the consequently, when transmission demand is low and, summer in lower is flexibility Downwards demand. by influenced heavily and seasonal highly is rates ramp residual downwards of 2.19Figure distribution the that shows System OperabilityFrameworkNovember2016
a a t t t
curve for August 2020. August for curve -100 approximately at maximum The latter case is suggested by the local suppressed by distributed solar generation. sunny days when transmission demand is during and demand) transmission is (as low is particularly overnight when gross demand MW for the the for MW
44 Chapter two 45 C er er MW/minute have been applied each to Figure 2.20 shows the growth in the number the in growth the shows 2.20 Figure of GB interconnectors. Existing ramp limits of 100 mainland and GB between interconnector Europe. Since there is a single GB market sensitive, are interconnectors all which to price there is a possibility of price changes causing rapidly ramp to interconnectors numerous at the same time. This means that the ramp limit risk GB to will increase with each new continues practice current if interconnector modification. without r re r re
e ree e
o t o to o Figure 2.20 Count of GB interconnectors Interconnectors projects, interconnector future majority of The numberby and transfer capacity, will connect GB mainland to Europe. The relative sizes of these systems means that a large and fast change in interconnector flows could have a detrimental effect in the GB system but be system. European the to negligible 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing GB interconnectioncapacity Figure 2.21 minimum summer of times at example, For real-time. in operator system to the available is that generation the of capacity the exceed will interconnection capacity, shown in Figure 2.21, of range increasing the export, or import net in change any of rate to the addition In t o to o t System OperabilityFrameworkNovember2016 o t t e ree
r re 19.1 respectively. GW 19.8 of capacity interconnector or 5.3 or 2.2 as low as be the decade, transmission demand might of end the towards demand transmission r re GW ( Gone Green GW ( Consumer Power C er er C er ), against an an ), against GW or GW or
)
46 Chapter two 47
0 Delay from start from Delay (mn) ramp of 0–10 10–15 20–35 40–50 GW importGW to 1 Quantity 11 2 4 3
GW import.GW In this example, in addition 999 12 50 8 5 Ramp rate rate Ramp (MW/mn) 1 storage,to there are generators 20 available from instruction after generation increase to the system operator, the details of which are given 2.2. in Table for example moving from 3 MW/minute each t
e erat r e erat r 2000
125 100 500 500 Headroom at start of (MW) ramp interconnector MW/minute. This represents
e a e erat e a t ra e GW (orGW increase net export the by
GW ramp over two interconnectors at 100 GW ramp over two interconnectors t o Type 4 Type 2 Type 3 Storage Type 1 Table 2.2 Table ramping examples Units available to system operator for interconnector Interconnector movement example 1:Interconnector movement 2 Figure 2.22 Figure illustrates 2.22 a case where two interconnectors reduce net flow into GB by 2 by 2016 November Framework Operability System same amount) each at their present allocated ramp rate of 100 a third of the interconnector capacity range between GB and mainland Europe in 2016/17, Chapter two Balancing and flexibility and Balancing Ramp ratesofreserveonconventionalplantandstorage Interconnector movementexample1: Figure 2.23 Table in 2.2. delays the per as dispatched are generators next The immediately. to respond able are 1generator type and storage the to ramp, start interconnectors the When System OperabilityFrameworkNovember2016 t t ra e
e er e e re ra p rate
t to displace the storage. the to displace generation can catch up, at which time it starts conventional the until rate ramp the satisfies throughout. Figure 2.23 shows how the storage Generation and demand remain balanced 48 Chapter two 49
GW. In this case, as Figure shows, 2.25 while there is sufficient capacityto initially match the ramp rate, there isinsufficient to sustain shortfall of generation a is result The it. approximately 2.3
t
MW/minute each
e erat r e erat r
t ra e e erat e a
GW over six interconnectors at 100 GW over six interconnectors GW movementGW over six interconnectors,
t o t o Interconnector movement example 2:Interconnector movement 4.9 Figure 2.24 In a second example, there Figure isa 2.24, 4.9 which is a third of the interconnector capacity with mainland Europe Power for Consumer generators dispatchable same The 2020/21. in are available as for the previous example. 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing and solar generation. counteract the increased from variability wind they as output of levels constant at time less spend and day per once than more off and on shifting of in terms flexible more to be need will units these that expectation an includes This adapt. to need will BMUs the profile, demand leads to changes in the daily transmission generation 2.16,Figure distributed in growth as As discussed earlier, with reference to 5. 4. 3. 2. 1. a system operability perspective: from flexibility to elements main five are There Flexibility Ramp ratesofreserveonconventionalplantandpumpedhydro Interconnector movementexample2: Figure 2.25 System OperabilityFrameworkNovember2016
Reactivesupport.
Ramp rates. Ramp t Controllability. Operationalrange. Synchronisation and de-synchronisation. t ra e
e er e e re ra p rate
t
to 35%, all the requirements can be satisfied. be can requirements to the 35%, all reduced is SEL 45%. of aSEL When for true is same The requirements. flexibility and demand the both to meet possible not is it capacity, 55% of of level atypical at set is units the of (SEL) limit export stable the When headroom. 300 least at 1000 is The real-time output required from these units 500 all units, sized to equally access has operator system the example, illustrative (headroom) and downwards (footroom). In this upwards requirements; flexibility and demand real-time between optimising when occurs that conflict the managing when range operational Figure 2.26 illustrates the value of an increased MW, and there is a requirement for for arequirement is there MW, and 600 and footroom of MW MW. MW of of MW
50 Chapter two 51 re flexible units re flexible units tr h rt a tr re flexible units Finally, all the other elements of flexibility are dependent on the fifth, which is the abilityto take instruction, either directly or indirectly from the system operator, for example via an aggregator. These requirements are the subject System Whole the in discussion detailed of Coordination chapter, see page 142. tr t ta ar ea r t ta ar t
ta ar ea r h rt a ea r tp t re re
These conditions are experienced during periods of low demand, particularly in advance of a forecast pick-up in demand – such as overnight before the morning pick-up. This and Balancing the in detail in discussed is Operability case see study, page 53. The first three elements of flexibility focus on fourth the however, balancing, power active recognises the need meet to reactive power provide that resources Energy requirements. flexible reactive power support in additionto active power are more valuable the to system operator than those without this capability. detailed of subject the are These requirements Management Voltage the in assessments chapter, see page 102. Figure 2.26 Demonstration of the effect of minimum generation output level Demonstration of the effect 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing There is a requirement, therefore, to develop to develop therefore, arequirement, is There energy resources in GB could respond. the of rest the than quickly more systems external and GB between flows power the interconnectors, which could potentially vary of growth the in evident particularly is This benefit. optimal for coordinated and controlled appropriately not if risks security to system lead could but output, flexible very for allow generation background. These characteristics has historically formed the of majority the restrictions of conventional generation, which physical same by the limited not are resources The technical capabilities of growing energy network voltage levels. system, at both transmission and distribution generation and demand across the whole in flexibility additional to develop necessary is It flexible. more becomes system power the of rest the that require sources energy Increasing capacities of variable output Conclusions System OperabilityFrameworkNovember2016
for on a cost reflective basis. reflective acost on for addressing these needs must be accounted providers other of cost the or movements, own address the requirements which facilitate their either therefore must flexibility of Providers create an imbalance in supply and demand. rapidly similarly could This signal. a price to response in devices fast-acting many of need to consider potential herding behaviour a is there grows, devices storage energy of capacity installed the as example, For signal. to aprice according output their technology which types can quickly change to other apply equally considerations same interconnectors, it should be noted that the While the assessments have focused on of today. of interconnection capacity above the level The requirement will grow with the addition effects. their managing of costs the and between GB and interconnected markets flow power of swings large for potential the by presented risks the to limit methods
52 Chapter two 53
– requires sufficient GW atGW noon on Saturday to overnightGW and into the static and dynamic reactive power covered as locations, right the in available chapter. Management Voltage the in of the largest generation or demand loss too changing from frequency prevent to quickly, as covered in the Frequency chapter. Management Rate of Change of Frequency (RoCoF) – requires sufficient system inertia or control Voltage regulation
of Friday 5 August, is shown in Figure 2.27. Wind generation was forecast rise to from approximately 1 approximately 7 early hours of Sunday. It was remain to high Monday. into and morning Sunday throughout High output from distributed wind and solar on particularly forecast, also was generation 2.28. Figure in shown as Sunday, and Saturday Chain of events: 5–8 August The chain of events demonstrates the complex operability different between interactions is which scenario a outlines and requirements expected be to more common in the future. generation wind transmission-connected The forecast for the weekend, as of the morning
– requires – – requires sufficient GW. It was particularlyGW. windy over the sufficient response availableto prevent operational above rising from frequency limits for the largest demand loss. High frequency response frequency High Downward regulation Downward output its reduce quickly to able generation manageto unexpected fluctuations in the demand. and supply of balance the issues which our Balancing assessment Balancing our which issues the enables us identify. to It also demonstrates the complex interactions between different one resolve to action where needs, operability requirement can create others. On the morning of Sunday 7 August we experienced the lowest transmission system demand in recent years, 16.3 demand, low of combination the and weekend meant output solar high and output wind high that a significant number of system operator interventions had be to taken for balancing different many operability While and reasons. to had interactions and operabilityrequirements be accounted for during this period, a number highlighted are areas challenging particularly of in this case study. Overview This section describes a real example of 2.5 Balancing and operability: 5–8 2016 August 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing Distributed windandsolargenerationforecast Figure 2.28 Transmission connectedwindgenerationforecast Figure 2.27 System OperabilityFrameworkNovember2016 t o o t t o w t o o t t tr te ar 20% confidence
r r r r tr te 40% confidence at at at at 60% confidence 80% confidence 54 Chapter two 55
MW. MW. MW.
GW of tradesGW were GW of windGW actions were also In addition to interconnector actions, actions, interconnector to addition In contracts for Demand Up were Turn used. Other contracts were used bring to more synchronous generators on at a low active synchronous additional Eight output. power generators bids were taken manage to voltage through the Sunday minimum Sunday the through voltage to had generators Other period. demand reduce their output create to room for these additional created which machines, eight challenges sourcing sufficient downward regulation. A total of 3.3 required source to downward regulation whilst optimising for RoCoF and voltage over the Sunday minimum demand period. A total of 2 taken manage to power flow constraints over the Scottish border. This also helped to requirements. regulation downward the alleviate manage to Trades RoCoF risks were required lowest The weekend. the throughout generation loss that would have resulted in breachingthe RoCoF limit was 678 This was recorded on Saturday at 14:30 single largest the time which at afternoon, 635 was risk generation of loss
GW
MW. MW. GW andGW MW, it wouldMW, GW at 04:30 on atGW Sunday 04:30 morning (16.3 sold over the Dutch interconnector. Dutch the over sold This limited the power which could be could which power the limited This have become the largest demand loss risk. there period, demand minimum the Over would not have been sufficient generation providing High Frequency Response for a demand loss of more than 580 out-turn). Forecasts also indicated that there would not be enough downward regulation. actions available all after that, meant This had been taken on flexible plant, the system operator may not have been able manage to any surplus of generation. There was a high risk of a negative reserve active power margin notice being issued. This is a request for additional flexibility and an indication that to issued be might instructions emergency disconnect plant that is not flexible or plant which does not participate in the Balancing low were GB in prices Electricity Mechanism. due high to wind and solar generation and low demand, therefore only the most efficient run to due were machines synchronous performed were Trades weekend. the over sellto power over the interconnectors. typically represent bipoles interconnector The Selling generation. of loss single largest the import reduces interconnectors the over power GBto which can help alleviate to both RoCoF by constraints regulation downward and increasing demand for power stations in GB. There were two limitations on the amount of power which could be sold over the interconnectors. Firstly, a control system interconnector French the limited issue export. Secondly, if an interconnector bipole had exported more than 560 The lowest transmission system demand system transmission lowest The was forecast be to between 16.1 17.1 2016 November Framework Operability System Chapter two Balancing and flexibility and Balancing to run which could provide these capabilities. capabilities. these provide could which to run to allow additional synchronous generation actions across the interconnectors were critical available downward regulation. Expensive the limited also and risks, RoCoF manage limited the capabilities to regulate the voltage, limited synchronous generation running. This very was there that meant weekend the over experienced demand low and generation solar The combination of high wind generation, high Conclusions System OperabilityFrameworkNovember2016 the interaction with operability needs. considering while flexibility additional for need interacting requirements. This highlights the simultaneous to manage has operator system be an increasing number of periods where the solar and wind generation increases, there will of penetration the As areas. other in needs increased but requirement, aspecific reduce requirements. Other trades were to necessary multiple satisfied actions trading the of Some 56 Chapter two 57 Action is required ensure to that rapid changes in interconnector power flows do not cause number growing The security risks. system and capacity of interconnectors present the risk that simultaneous changes in flow across a to combine could interconnectors multiple net movement that is greater than the capability respondto of the energy resources within GB. This risk may equally apply other to fast- types technology price-sensitive and acting in the future as installed capacities for grow, example energy storage devices. The risk of synchronised movements is high due to are which arrangements, trading capacity organised in fixed time periods throughout the Thereday. is therefore a requirement develop to power changes in rapid that ensure to methods importor export do not present system security operability disproportionate cause nor risks, costs accommodate to them.
as well as varying output while synchronised. while varying output as well as further develop to opportunities are There periods services demand-side both during of high and low demand. The periods of low demand are likely be to an area for growth over the next decade. interconnectors lead can conditions Market operateto in a way that is detrimental the to operability of the system. This becomes a risk small not is capacity interconnection when relative the to rest of the generation thatis There operator. system the by controllable is therefore a requirement for the system control to capability the maintain to operator interconnector flows without havingto resort emergencyto protocols. Balancing resources will need to become to need will resources Balancing increasingly flexibleto facilitate the use of intermittent and variable sources of power generation. This includes the ability to desynchronise, and synchronise frequently 2.6 Consequences and requirements 2016 November Framework Operability System Chapter two System OperabilityFrameworkNovember2016 58 Chapter three
59 59 60
Frequency managementFrequency three Chapter Chapter 2016 November Framework Operability System 2016 November Framework Operability System Chapter three Frequency management Insights 3.1 System OperabilityFrameworkNovember2016 coordinated across theindustry. are replaced, whichneedstobe protection settingsare changedorrelays The limitcannotberelaxed untilgenerator in theeventofafrequency disturbance. disconnection ofdistributedgeneration specified limittoavoidtheunwanted System inertiacannotfallbelowa inertia islow, whichoccursmore often. Frequency ismore volatilewhensystem system operator. will require greater interventionfrom the generation isrunning,lowsysteminertia When limitedlarge synchronous
of frequency management solutions. would facilitatemore efficientdevelopment A review offrequency response services often referred toassyntheticinertia. active powerafterameasurement delay, Inertia isdistinctfrom thefastinjectionof 60 Chapter three 61
Hz and as close as possible Hz and 50.5 As frequency changes, frequency response response frequency changes, frequency As to output their decrease or increase providers aims action This imbalance. power the reduce arrestto and contain frequency excursions. required usually are Further balancing actions thereafter restore to the frequency its to reserve. of providers through value nominal for responsible is operator system The maintaining an adequate level of frequency response and enough reserve ensure to the ranges operating the within remains frequency defined in the Security and Quality of Supply Standards and the Grid Code, between 49.5 to 50 Hz. Frequency is the number of alternating current current alternating of number the is Frequency cycles per second of the power system. It is determined the by speed of the generators and motors that are synchronised the to system. balanced, are demand and generation When a is there When constant. remains frequency power shortage, for example due a loss to of supplied shortage is power the generation, from the energy stored in the rotating masses of machines that are directly coupled the to system. This slows these machines down and, frequency. system the reduces consequently, When there is a power surplus, the opposite rise. to frequency causes action following changes frequency which at rate The a loss of generation or demand depends on the total amount of energy stored in the inertia of rotating masses which are synchronised to energy more high, is inertia When system. the is stored in rotating masses and the frequency change is slower. In general terms, the bigger and heavier a machine is, the more inertia it has. This includes drive that turbines the from contributions the the generator, the fluid that drives the turbines inertia As loads. mechanical other any and increases, so does the effort required speed to the machine up or slow it down. Thedesigns biomass, gas, (coal, stations power thermal of nuclear) and large hydro power stations require which components rotating large of use the 3.1. Figure in illustrated inertia, as high have 3.2 frequency What is management? 2016 November Framework Operability System Chapter three Frequency management system inertia. system to contribute not do interconnectors, or moving parts, such as solar photovoltaic have not do that technologies addition, In machines from contributing to system inertia. of power electronic converters, prevents to use due example for coupling, direct this of rotor. absence The machine the on acts that torque amechanical into translated to be coupling allows disturbances on the system direct This system. power the and machine electromagnetic coupling between the adirect to be has there inertia, system to to contribute amachine for order In and induction motors. synchronous generators, synchronous demand smaller as such sources, by other provided is rest The system. power the with synchronised by largeconventional power stations that are provided is inertia 70% system of Approximately system. to the coupled are that motors) and (generators machines rotating the of all of inertia aggregated the is inertia System Sources ofinertia Figure 3.1 System OperabilityFrameworkNovember2016 Water Fuel
Boiler Steam turbine pressure High Steam turbines turbine pressure Intermediate
turbine pressure Low speed of one conveyor belt will affect the other. the affect will belt conveyor one of speed the in achange analogy, 3.2. this In Figure in shown as system, power the and generator conveyor belts that represent a synchronous two connects that achain as visualised Synchronous or direct coupling can be generator haveinertia Spinning turbinesand 50Hz 3000 rpm Generator = Power Transformer as householdsocket The samefrequency Network 62 Chapter three 63
= rpm 3000 50Hz Power system Power system = rpm 3000 50Hz system having to be connected and moving moving and connected be to having system at the same speed. This is shown in Figure 3.3 conveyor one of speed the in change a where belt will not affect the other.
Synchronous coupling Synchronous No synchronous coupling No synchronous speed Variable Synchronous generator Synchronous Non-synchronous generator Non-synchronous
Figure 3.3 Generator without a synchronous coupling Non-synchronous or indirect coupling can coupling indirect or Non-synchronous be visualised as a roller that allows the transfer of power (represented boxes) by between the power the and generator the without belts two Figure 3.2 coupling Generator with a synchronous 2016 November Framework Operability System Chapter three Frequency management The combination of frequency response disturbance. a following seconds 60 first the over place 3.4, takes Figure in shown frequency containment phase which, as the on concentrate we chapter, this In Frequency managementtopicmap Table 3.1 Topic map 3.3 System OperabilityFrameworkNovember2016 Containment Frequency Frequency of Change of Rate Injection Power Active Fast System Inertia Assessment
the suitability of existing service definitions for the future. the for definitions service existing of suitability the An of assessment changing frequency containment needs and impact on inadvertent distributed generation protection operation. the and frequency of change of rate increasing of assessment An inertia. synthetic to as referred often injection, power active fast and inertia system between differences the of assessment An assessments. management frequency other in needs control and stability An assessment of decreasing system inertia which affects Description
frequency regulation. frequency to steady-state to return adisturbance following phase recovery the for required capability the with operator system the provides general, in within these 60 seconds and additional reserve,
84–100 77–83 73–76 68–72 Pages 64 Chapter three 65
e re e e t te t te te explores the te e er re e Rate of Change of Frequency explores ability of frequency response arrest to the drop in frequency following a loss of power supply, or rise following the loss of demand, without exceeding the limits defined in the Grid Code and the Security and Quality of Supply Standards. the rate at which frequency changes following following changes frequency which at rate the a disturbance. It needs be to limited prevent to loss of mains protection from disconnecting enough provide to and generation distributed contain to response frequency for time excursions. frequency Containment Frequency t t r e e
re e t r e t e t e e a e a e erat e erat re e e t is a characteristic of the te t te te
re e re e is available in the rotating masses of all machines that are directly coupled the to any balance instantaneously to system surplus or deficit in power. Fast Active Power Injection explores possible as quickly as power of injection the after a measurement delay. This is not the we which distinction a inertia, as same investigate in this section. System Inertia System system that defines how much energy Figure 3.4 requirements with respect to time Illustrative frequency management 2016 November Framework Operability System Chapter three Frequency management Annual rangesofsysteminertiashowingthelowestandhighestvaluescenarios Figure 3.5 it contributes. on the largest loss and how much inertia to 8 up be can inertia lowest pre-fault The generators. by distributed used relays protection mains of loss by some imposed frequency of change of rate post-fault on restriction to the due is This generators. inflexible to disconnect instructions emergency fault without deloading nuclear generators or 130 than lower no be can inertia management requirements. Currently, system inertia becomes the major driver for frequency proportion of non-synchronous generation, increasing to the due drops inertia system As requirements and Consequences 3.4 System OperabilityFrameworkNovember2016 2025/26 2020/21 2016/17
GVA.s higher depending depending GVA.s higher r re er er e ree GVA.s post-
t ert was 135was past recent the in experienced been has which scenarios highlighted. The lowest system inertia all across values minimum and maximum the with decade, the across changes inertia system Figure 3.5 shows the range of unconstrained GVA.s on 7 August 2016.GVA.s 7August on e ree e ree r re 66 Chapter three 67 The drop in inertia and increase in the largest generation or demand risk will require the response frequency new of development in approaches new of design The solutions. the medium and long term is likely require to a review of existing frequency response services.
. flexibility case A Provision of inertia at times of low transmission transmission low of times inertia at of Provision increasing require currently would demand to operator system the from intervention even run, to generators conventional instruct if they are out of economic merit. This case is represented in our assessments by 2016 November Framework Operability System Chapter three Frequency management system frequency and damp disturbances. the to regulate acts behaviour This demand. and order to maintain between generation equilibrium in system power the and machines rotating the transferred between the kinetic energy stored in is energy imbalance, apower is there When times. all at out power equal must in power that The principle of conservation of energy dictates inertia. less with one than system power the of out or in energy more transfer will inertia greater with amachine speed, in change same the For machine is proportional to its rotational inertia. each in stored energy of amount The versa. vice and energy kinetic of store to the system power speed increases, energy is transferred from the varies with their speed of rotation. When their stored energy kinetic The rotors. their in energy kinetic store motors and generators Rotating Background excursions.of frequency the magnitude which increases systemreduce inertia will conventional in large generators A reduction inertia System 3.5.1 Assessments 3.5 System OperabilityFrameworkNovember2016
100 200 with asystem of behaviour the compares It after 1000 seconds two first the in respond system power a30 of simulations how 3.6 shows Figure demand. of aloss for true is opposite The demand. and must equal the imbalance between generation store energy kinetic the of out transferred moment of the loss of generation, the power the From system. power the of frequency electrical the does so consequently, and down slow machines coupled the that means system power to the store energy kinetic the from transfer this generation, of aloss of case the In GVA.s. GVA.s of system inertia to one with with to one inertia GVA.s system of
MW is instantaneously disconnected.
GW GW
68 Chapter three 69
Hz, only ±2% e GVA.s) GVA.s, thisGVA.s, equates to
GW. re e re e vs 100 GVA.s In summary, the term ‘system inertia’ is used as a convenient describe way to the quantity of kinetic energy stored in the rotating parts of the machines that are coupled the to power system. It is expressed which in GVA.s, is equivalent GJ. Thisto relatively small store of usable balance the regulate to helps inherently energy demand. and generation between The amount ofthis energy store that is used for managing frequency is restricted the by frequency limits being applied. For example, for a frequency deviation of ±0.5 of the stored kinetic energy can be transferred before the frequency limit is exceeded. For a system with 200 GJ) (4 or approximately4 GVA.s 4 seconds for an imbalance of 1 e
MW generation loss (200 e . The reduction reduction The . 1 MW. In orderMW. to e
MW. As a result,MW. those machines start
ert a te er r ert ert r er This relationship is explained in more detail on page 84. 2016 November Framework Operability System 1 Immediately after the disconnection, there there disconnection, the after Immediately is an imbalance of -1000 stored energy kinetic the balance, achieve be starts to machines synchronous the in transferred the to power system at a rate of 1000 falling the by shown is which down slow to reducing the of consequence A frequency. frequency is a reduction in the power demand from motors, which is proportional frequency. to Based on observation, this currently drops by approximately per Hertz 2.5% Figure 3.6 for a 1000 The power from inertia in demand reduces the size of the imbalance, so the rate of energy transfer from the kinetic energy store the to power system reduces by the same amount. The sum of the power from inertia and the reduction in demand is always There loss. generation initial the of size to equal is an assumption that no frequency response is period. this in delivered Chapter three Frequency management Annual distributionsofsysteminertia(GVA.s) byscenario(flexibilitycaseB) Figure 3.7 low levels of increases. inertia decreaseinertias and the proportion of time at system lowest and highest the both scenarios, B case flexibility for scenarios all for decade the across changes inertia system of distribution the how 3.7 shows Figure reduces. time particular any at running transmission connected generation that is In all scenarios the proportion of conventional Results System OperabilityFrameworkNovember2016
Consumer Power te ert te ert te ert No Progression . In all all . In
Consumer Power Gone the Green under common most This level inertia will eventually become the requirement. flexibility its for operator system the close to the minimum number of units required by in Figure 3.7 show that the system is running The peaks on the side left of the distributions Slow Progression te ert te ert te ert Gone Green scenarios. and and
70 Chapter three 71 , . C and Progression Slow Gone Green te ert te te ert te Slow Progression No Progression No systeminertia is higher fora greater proportion of time. The lower capacities of distributed generation in these scenarios do not interact with the system operator’s flexibility requirement for distributions similar the by shown often, as flexibility cases B and plant on run to when they otherwise would not. In
C and Green Gone GVA.s in allGVA.s scenarios. No Progression te ert te te ert te Consumer Power
Figure 3.8 shows that holding by the flexibility flexibility BMUs, conventional on requirement inertia system case lowest the A maintains at approximately 125 In Power the Consumer e t a e scenarios, the higher levels of non-synchronous non-synchronous of levels higher the scenarios, generation conventional displace generation more often so that the system operator’s conventional constrains requirement flexibility Figure 3.8 and flexibility case (2020/21) by scenario system inertia (GVA.s) Annual distributions of 2016 November Framework Operability System Chapter three Frequency management The level of system operator intervention, intervention, operator system of level The inertia. system toward contributor major the that displace large conventional generators, ofcapacity non-synchronous energy resources growing by the caused is This increase. will inertia low at runs system the when time of throughout the decade and the proportion reduce will inertia system of level lowest The Conclusions System OperabilityFrameworkNovember2016 capacities of non-synchronous resources. greater with scenarios for greater is intervention this of impact The floor. inertia a minimum synchronous resources, effectively creates by non- displaced be otherwise would they when flexibility, of purpose the for running Keeping part-loaded conventional generators inertia. system of distribution the modifies requirement, flexibility the as expressed here 72 Chapter three 73
there is interest in new approaches address to the inertia gap. The following explains the differences between the behaviours of system injection. power active fast inertia and With existing providers of system inertia closing, ultimately and often less running
is the exchange 2
Fast active power injection is described here as power input situation. converse in the response to equally to demand exceeding supply. The principle applies 2 Background System inertia is a measure of the kinetic energy stored in the rotating components of machines coupled the to power system. machines these of behaviour inherent The the through frequency changes in opposes transfer of power between their stored kinetic energy and the power system. injection power active Fast System inertia is an inherent characteristic machines of 3.5.2 injection power active Fast that are coupled to the power system which naturally which and system are power that the coupled to This is frequency. damp disturbancesimmediately system to injection aftera measurement distinct from power fast active sometimes referred inertia. as synthetic to delay, 2016 November Framework Operability System of power between a unit that does not contribute system to inertia and the power system. This requires the measurement of time a necessitates which variables, system delay for the measurement be to taken and respond. to system control associated the It is often referred as to synthetic inertia, but equivalent is behaviour its that means delay the veryto fast frequency response. Chapter three Frequency management 100 20 with System OperabilityFrameworkNovember2016 1000 Figure 3.9 er r ert 1000 of loss instantaneous an of case the in inertia from transferred is power how 3.9 shows Figure Results te ert a GVA.s of system inertia, the rate of change change of rate the inertia, GVA.s system of MW generationloss GW of demand. In the case with with case the In GW demand. of e e
MW of generation on a system asystem on generation of MW e e e
re e active power injection. fast with asystem to compare which against -0.125 is which example, of -0.25 value reaches(RoCoF) a minimum offrequency e e
200 the for that twice Hz/s,
te abaseline is This Hz/s. e e GVA.s 74 Chapter three 75
e
te te GVA.s). e
re e re e period, no response is delivered and the system behaves in the same way as the previous example. Following the active power injection, the apparent loss is halved and the rate of change of frequency becomes similar the to system of level the twice with simulation inertia (200 MW of fast active power injection at 300ms MW of fast active power e
e e GVA.s. TheGVA.s. 300ms period
e MW generation loss with 500 MW generation loss with
te ert a te er r ert ert r er Figure 3.10 repeats the simulation but adds adds but simulation the repeats 3.10 Figure an active power injection at 300ms for the systemwith 100 is representative of the time necessary to measure system variables with the confidence that they are not being distorted temporary by measurement the During disturbances. local 1000 Figure 3.10 2016 November Framework Operability System Chapter three Frequency management delayed response of an active power injection. the and inertia system of support immediate the between distinction the to make necessary is it 200ms, as short as periods for frequency of change of rate to the sensitive are devices some that Given it. to stabilise frequency in change the demand, system immediately inertia opposes an unplanned disconnection of generation or of case the In market. energy by the valued explicitly not is and machines synchronous of characteristics the of aconsequence as provided is It frequency. to regulate acts that System is inertia an inherent mechanism Conclusions System OperabilityFrameworkNovember2016 be directly exchanged with system inertia. system with exchanged directly be cannot 84), these (page Containment Frequency in discussed as required, are power active of sources controllable and to fast access While dynamics. system to undesirable lead could that network weak arelatively on aresponse such of consideration should be given to the distribution by local or transient conditions. Furthermore, response would not be erroneously triggered any that to ensure necessary is it but reduced, Measurement and processing times could be practical solution is yet to be demonstrated. development of theoretical methods, but a the in interest academic ongoing is There 76 Chapter three 77
[MW]
[MVA.s]
Inertia Inertia Imbalance Imbalance × [Hz] 2
50 ] = Hz/s The original RoCoF settings of the loss of mains protection devices were based on a power system in which the minimum inertia was relatively high. As the minimum system which protection RoCoF-based of settings the would result in unnecessary loss of distributed generation of loss large a If generation. widespread a by followed immediately was the generation, distributed of disconnection severely a have would imbalance resulting and frequency system on effect detrimental further disturbances. to lead could mitigateTo this risk, the system operator takes action limit to the rate of change of frequency are the two variables that the system operator adjust. can inertia drops, RoCoF levels resulting from generation loss or demand loss could exceed caused imbalance the for occur would that a largeby instantaneous loss of generation or imbalance of function a is RoCoF Since demand. following the in shown as inertia, system and equation and these graphically in Figure 3.11, RoCoF [
GW of distributedgeneration of inadvertentlyGW could disconnect Background Some faults, once cleared, may result in the network distribution the of sections of isolation from the rest of the power system. If the output section isolated the in generation distributed of matches the demand, it may form a self-sustaining power island that operates at a frequency, voltage, and phase angle that are different the to main (DNO) owner network distribution the As system. tries restore to this section, there could be a personnel. and plant to risk material is generation distributed risk, this mitigate To required be to fitted with‘loss of mains’ protection subsequently and events islanding detects that disconnects the generator from the system and forces the power island be to shut down. connection the restore to DNO the allows This thatto part of the network in a safe and secure manner. When the network has been restored, reconnect. can generator distributed the to available methods common most the of One detect islanding is based on the rate of change of frequency (RoCoF). This method assumes that islanding of a section of distribution system will result in a RoCoF that is higher than that generation/demand normal with associated loss events on the system. Falling system inertia system over that increasesFalling likelihood the Rate of change of frequency change of of Rate 3.5.3 6 protection systems sensitive overly to due based change frequency. on of rate of 2016 November Framework Operability System Chapter three Frequency management synchronous compensators instructing pumped storage units to act as involve also can It to de-load. units large network topology, before instructing individual to due fault asingle of aresult as disconnected being of risk at are that generators large of output the restricting and flows interconnector inertia. This involves typically repositioning system to increase units more to synchronise the point where it becomes more economical until reduced therefore is demand or generation of loss potential largest the of size The risk. loss largest the of size the to reduce than unit generating extra an by synchronising inertia to increase expensive more much generally is It Instantaneous absoluteRoCoF, relationshipbetweenabsolutelosssizeandinertia Figure 3.11 6 5 4 3 System OperabilityFrameworkNovember2016 of a RoCoF of 0.125 of aRoCoF of actionsThese are taken to minimise the risk of and increasing demand. inertia effect combined the has which to pump, or air, which has the effect of increasing inertia, Figures submitted to the Distribution Code Review Panel GC0079 - http://www2.nationalgrid.com/UK/Industry-information/Electricity-codes/Grid-code/Modifications/GC0035-GC0079/ information more For generators. 146. page see distributed of visibility, about majority vast the from data operational mode. receive not does compensation operator system The asynchronous in running of capability the have that generators conventional of number asmall also are There te h e re e
Hz/s because the quantity quantity the because Hz/s 3 by spinning in te ert te ert
operator in real-time in operator system to the unknown is risk at generation of level precise the but large, is protection as a result of spurious action of RoCoF-based of the generation that could be disconnected this type of protection is at least 5 least at is protection of type this with generators smaller of capacity total the of 1.5 was category this in units for capacity generation remaining 5 than greater acapacity with generators for relays RoCoF replace or to change programme this of working group Code Distribution and Code Grid ajoint of including RoCoF protection, under the guidance systems, protection relevant the update or to replace programme ongoing an is There on generators of this size. this of generators on fitted to be systems protection RoCoF-based Distribution Code presently still permits new MW. As of September 2016, the MW. September of As 5 . Figure 3.12 shows the progress 3.12. Figure progress the shows GW. The most recent estimate estimate recent GW. most The 4 . GW 6 and the the and 78 Chapter three ;
79
and Green Gone Hz/s, the present ) is driven the by due the higher levels levels higher the due MW capacity Slow Progression Slow Consumer Power Consumer and Results the of distributions annual the shows 3.13 Figure size of generation or demand loss that would result in a RoCoF of 0.125 reduces limit scenarios all the In limit. RoCoF throughout the decade as a result of falling systeminertia, and increasing unit size. The effect is seen sooner under Green Gone and between 2020 and Progression for 2025 No generation non-synchronous of growth relative in each scenario. small of growth continuous the to addition In largest the generators, non-synchronous steps occur when new interconnectors are connected. Their impact is also dependent on import power they that time of proportion the low of periods import during they whether and demand. transmission of non-synchronous generation, and for the for and generation, non-synchronous of same reasons the limit is lower for a greater left side the shift in The time. the of proportion and 2020/21 (between shape distribution of 2020 Power for Consumer
2016 concentrates 2016 Cha e
pr re
e er t t t e er t When the programme has been completed completed been has programme the When for all generators, the RoCoF system’s limit will instead be driven the by capability of of limitations mechanical the or response generators withstand to the loads placed on them as a result of rapid frequency deviations. than restrictive less being limitations, These those presented RoCoF-based by protection, are not included in the following assessments. There is a small but growing amount of evidence that a different type of loss of mains spuriously could shift’, ‘vector called protection, RoCoF as conditions similar in operate protection. This is being considered the by SOF group. working same only. protection RoCoF on Figure 3.12 RoCoF relay settings for distributed generators greater than 5 RoCoF relay settings for 2016 November Framework Operability System Chapter three Frequency management ( Annual distributionofmaximumlosslimitforaRoCoF0.125 Figure 3.13 System OperabilityFrameworkNovember2016 flexibility caseB) Consumer Power
No Progression t t Slow Progression Gone Green t t Hz/s by scenario Hz/s byscenario 80 Chapter three 81
1600 1600 1200 1200 Hz/s by flexibility case 800 800 Loss limit (MW) limit Loss Gone Green Loss limit (MW) limit Loss Slow Progression 400 400 0 0 operator’s flexibility requirement being held on conventional plant. When more of this flexibility system reducing elsewhere, held is requirement that intervention the and reduces limit the inertia, would be necessary manage to the risk presented increases. protection RoCoF-based by 1600 1600 Hz/s C 1200 1200 B 800 800 A Loss limit (MW) limit Loss (MW) limit Loss No Progression
Consumer Power 400 400 0 0 2020/21 Figure 3.14 maximum loss limit for a RoCoF limit of 0.125 Annual distribution of Figure 3.14 shows the distributions of the loss the of distributions the shows 3.14 Figure size that would result in a RoCoF of 0.125 scenario by in 2020/21 and flexibility case. Within each scenario, the left-hand side of the distributions are driventhe by lower levels of system inertia as a result of the system 2016 November Framework Operability System Flexibility case: Chapter three Frequency management 1000 from reduced limit loss largest to 1000 least at of connections Slow in Progression example, For limit. by the affected units of number the The amount of intervention increases with 53. page study, see case operability the 2016 summer minimum balancing and in discussed is this of experience Recent de-loaded. to be have generators where level to the reducing limit loss maximum the of in 2020/21in minimum summer the of time the at units 50 Figure 3.15 shows the initial position of the largest System OperabilityFrameworkNovember2016 7 Largest 50unitsatsummerminimum2020/21byscenario Figure 3.15 positions of the interconnectors on the day of the 2016 summer minimum case study. case minimum 2016 summer the of day the on interconnectors the of positions 2000 of 1000 as modelled connection are combined one interconnector French the of bipoles two the assessment, this of purpose the For e er t e er t Consumer Power ter e t r 7 . It demonstrates the significance significance the demonstrates . It Consumer Power
No Progression t t t t t t t t which has seven. If the ear MW. The initial position of each interconnector is set to full import to reflect the initial market market initial the toreflect import tofull set is interconnector each of position initial MW. The MW, compared MW, compared there are three three are there MW to to MW ther
MW in in MW 900 by its technical design. limited be may flexibility generator’s A nuclear markets. connected two the between price relative the on depends intervention the of cost the and system connected the of state the on depends flexibility interconnector’s An actions. these of difficulty the affects unit of type The are interconnectors and nuclear generators. demand low of aperiod during units largest the of 3.15 majority the that Figure shows also in 700 but capacity, of 300 to reposition have would operator Consumer Power e er t e er t Slow Progression Slow Progression t t t t t t t Gone Green MW for the same event event same the for MW . MW each, instead of of instead each, MW , the system system , the MW MW
82
Chapter three 83
. When importing, When . MW at alltimes. disconnects. The precise level depends on the the on depends level precise The disconnects. of output inertia power and of combinations nuclear the of level the Below units. largest the generators, there exist other constraints such or Green 2020 in Gone manageto this risk increases in terms of both duration. and magnitude as thesize of the largest demand loss, which conventional displace interconnectors contribute otherwise would which generation systemto inertia. Depending on flow direction, largest the become can interconnectors risk. loss generation or demand The level of intervention that will be required is approximately 560
r e t e er t r e r GW of distributedGW GVA.s higherGVA.s accountto
GVA.s, as This shownGVA.s, in Figure 3.16.
t t te ert ert te t t Conclusions The exposure the to risk of inadvertent disconnection of over 6 protection use currently which generation, systems based on the rate of change of frequency, rises as system inertia falls in scenarios. all There is a step change in this risk when the first which completed, is interconnectors new the of could be as early Power in Consumer as 2019 Figure 3.16 for system inertia Minimum post-fault requirement If the nuclear units are not deloaded, the minimum system inertia limit is approximately 130 pre-fault The requirement. post-fault a is requirement is up 8 to for the inertia that could be lost when a unit 2016 November Framework Operability System Chapter three Frequency management is true for high frequency; they speed up and and up speed they frequency; high for true is same The reduces. demand power their down, because as these synchronous machines slow of demand that is synchronous will reduce frequency. When frequency falls, the portion Synchronous demand is to proportional topic. the to relevant much very is variation frequency of containment assessment; however, the speed frequency the from excluded are protection with spurious actions of RoCoF loss of mains The risks and consequences associated and inversely proportional to system inertia. proportional to the size of the power imbalance are changes 77. frequency of page speed The background, RoCoF the in explained is inertia system and size loss changes, frequency The relationship between the speed of D. C. B. A. frequency containment are: for requirements the affect that variables The response services. frequency static and dynamic of by amixture frequency is contained within limits prescribed to 50 close frequency to keep output their vary that providers managed by dynamic frequency response In normal operation, frequency regulation is Background procurement. economic and would design facilitate their efficient services response volatile. more becomes Asystematic review of frequency frequency as quickly more contained be must Disturbances containment Frequency 3.5.4 8 System OperabilityFrameworkNovember2016 The relationship is periodically reviewed as the demand background changes. system inertia system secured loss size loss secured synchronous demand frequency limits
Hz. After a disturbance, adisturbance, After Hz.
Demand 50 from diverges f afrequency, at demand where below, shown is specifically lag time and ramp time. time. ramp and time lag specifically – variables definition service relevant the of some of effect the to demonstrate assessment Generic response designs are used later in the developed. to be services new facilitate and innovation to promote is approach this for by particular service definitions.The rationale frequency response without being constrained of requirement changing the to articulate us was no frequency response. Using time allows there if exceeded being limit frequency the and demand, or generation of aloss disturbance, the between time the is This –time. interest of variable asingle drive variables These response much act. from synchronous demand, and the faster that support less is there because requirement The tighter the limits, the greater the response variables to drive the response requirements. three other the with combine limits Frequency observed system dynamics synchronous demand has on demand from that effect the We infer demand. or generation of loss the of size to the equal necessarily not is of the reasons why the response requirement one is and frequency to regulate helps feedback negative This increases. demand power their , varies by 2.5% per Hertz as frequency frequency as by 2.5% Hertz per , varies f = Demand =Demand Hz. 50 Hz Hz x [1 –2.5% –f ×(50 8 . The relationship
)] )] 84
Chapter three
85 Hz, Hz,over ten seconds as illustrated in
H High frequency response is the minimum the is response frequency High reduction between seconds 0 and 10 and thereafter. sustained Secondary minimum the is response and seconds 30 and 0 between increase minutes. 30 for sustainable for 30 seconds. 30 for Primary response is the minimum increase minimum Primary the is response sustainable and seconds 10 and 0 between from 50 3.17. Figure response a linear to ramp of frequency ±0.5 Hz.For the frequency Hz for a low-frequency Hz for a high-frequency event. 50.1 Hz to
S P containment assessments, the initial frequency frequency initial the assessments, containment is assumed be to 49.9 event and 50.1 Existing response definitions The Grid Code specifies the minimum dynamic performance requirements for plant in frequency sensitive mode. It defines‘Primary’, response frequency ‘High’ and ‘Secondary’ as thechange in active power delivered in Grid Code response definitions Figure 3.17 In normal operation, frequency is typically in the range of 49.9 2016 November Framework Operability System Chapter three Frequency management Primary and Secondary response first ramps ramps first response Secondary and Primary both provides that aunit how demonstrates procured independently of Primary. Figure 3.18 be cannot Secondary dynamic that such Primary for that on dependent is response Secondary of definition the example, For services. existing to the changes on restrictions as well as services, new of development the of response leads services to constraints on definitions as criteria performance minimum Code Grid the of use The Code. Grid the of requirements to the subject not are who providers from are which of some procures, Demonstration ofthedependencySecondaryresponseonPrimary Figure 3.18 response services dynamic High and Secondary Primary, the define to used are definitions same The 9 System OperabilityFrameworkNovember2016 proportional to frequency deviation and therefore do not have the same interactions as the dynamic services. dynamic the as interactions same the have not do not are therefore and frequency, aset-point at deviation triggered to frequency are they because proportional here as excluded are They timescales same names. the in same the operate with that services services dynamic the response static for used also are ‘High’ and ‘Secondary’ ‘Primary’, names The e e e e e
e 9 that the system operator operator system the that r ar
of extra Primary response. Primary extra of need no but response Secondary extra requires well as the system operator which sometimes meet the requirements of response, Primary as response whoSecondary service are unable to independent an of providers potential limits This undeliverable. becomes profile the Primary, for that from separated is profile response completely implicit. When the Secondary transition between the is two services classed as response. Secondary The response. After 30s, all of its response is Secondary to deliver starts and response Primary to deliver 2s.of At 10s, continues it alag by 10s after response to Primary up e e ar e ar
86 Chapter three 87
e ar e a short duration, as shown in Figure 3.19, to sitto in front of the existing Primary and services.High
r ar h e
e
ha e e e e e Figure 3.19 response service Initial concept for Enhanced Another example is given the by definition of the new Enhanced response service, which service, response Enhanced new the service with fast a be to proposed initially was 2016 November Framework Operability System Chapter three Frequency management Final designofEnhancedfrequencyresponse Figure 3.20 Network Innovation Project The ‘Enhanced Frequency Control Capability’ transition between one and service another. the to manage afacility not was there because services existing the with compatible be not would aservice such that apparent became Through the development service process it System OperabilityFrameworkNovember2016 10 10 this purpose, among other objectives. other among purpose, this for systems control and monitoring improved
FC http://www.nationalgridconnecting.com/The_balance_of_power/EFCC: e e e
e h ha e r ar 10 is researching is researching between it and the other response services. experienced be would that interactions of instructions and therefore removed the risk the timescales of manual system operator into response Enhanced the extended This 3.20. Figure in shown as to 15 minutes, seconds ten from delivery response extend considerations that led to the decision to This constraint on the design was one of the e e ar
88 Chapter three
89
Hz
Hz, Hz. MW Hz). . For 11 MW on
Hz to 50.5Hz to Hz/s over 0.4 GVA.s thisGVA.s would occur in 2s. GVA.s of systemGVA.s inertia, C t t C response, is driven by these variables these by driven is response, example, a loss of demand of 1000 a system with 200 frequency would move from 50.1 This is superimposed on Figure 3.21. limits which constraint, RoCoF operational The the exposure the to risk of losses that would result in absolute RoCoF exceeding 0.125 containment the constraining of effect the has time at least to 3.2s (0.125 in 4s, but with 100 GW transmission demand MW or smaller. The frequency limit for a demand loss of any size is 50.5 MW due to the frequency containment limit for generation loss larger than 1000 e er t e r e e Hz for losses of 1000
Hz, where it is 49.5
t e t t e t e t e t The discontinuity that occurs at -1000 is 49.2 11 Figure 3.21 Unmitigated frequency containment time, 20 Results time Containment As covered in the Balancing andSystem Inertia sections, the size of the largest generation and system and increase will connections demand scenarios. all in period the over fall inertia will The combined effect of these variables is to response frequency which in time the reduce must deliver. Figure shows 3.21 how the time for frequency to move a frequency to limit, without any frequency 2016 November Framework Operability System Chapter three Frequency management System OperabilityFrameworkNovember2016 Annual distributionsoflowfrequencycontainmenttime,byscenario Figure 3.22 units that would otherwise contribute to to contribute otherwise would that units generation, which displaces the conventional by the behaviour of non-synchronous frequency limit. The distributions are dominated of the largest generation loss and the relevant size the inertia, system of by interaction driven for low frequency containment times by scenario Figure 3.22 shows the annual distributions of flexibility case B case flexibility Consumer Power
t e t t e t e t t e No Progression . The distributions are
increases in interconnector capacity. Slow Progression No 2025/26 for Progression and and 2016/17 Consumer 2020/21 for Power and between occur that changes step The risk. loss largest the often are interconnectors on flows import the addition, In inertia. system Gone Green Slow Progression t e t t e t e t t e Gone Green , and between 2020/21 2020/21 between and , , are caused by associated by associated caused , are and and
90 Chapter three 91
Hz as appropriate) within Gone Green t e t t e t e t e t t e t e t Slow Progression Hz or 49.2 BMUs. As this is reduced, the proportion of in shown as – inertia increases low with time where time of proportion the and 3.7, Figure frequency is at risk of reaching its containment limit (49.5 2 seconds increases. seconds 2
C No Progression t e t t e t e t e t t e t t e t e t e t
Consumer Power Figure 3.23 low frequency containment 2020/21 Annual distributions of Figure 3.23 shows how the distribution of containment time varies flexibility by case for each scenario In particular, in 2020/21. the left-hand side of each distribution is affected theby proportion of the system operator’s flexibility requirement held on conventional e t a e 2016 November Framework Operability System Chapter three Frequency management 50.5 to contained to be have would frequency exporting, while interconnectors these of one of to 1400up These become the largest demand loss risk, interconnectors. the through export gross of Power interconnection and renewables in Consumer of growth the is interest particular Of scenario. by times containment frequency high of Figure 3.24 shows the annual distribution System OperabilityFrameworkNovember2016 Annual distributionsofhighfrequencycontainmenttime Figure 3.24 Hz. Assuming an initial frequency of of frequency initial an Assuming Hz. and Gone Green and MW. In the case of a disconnection adisconnection of case MW. the In Consumer Power
t e t t e t e t t e No Progression , leading to periods
rm 50.1 Hz). from to 49.2 to fall allowed is Unlike generation for losses which frequency interconnectors, when system is inertia low. other across imports high were there if or output onerous at times of high renewable generation particularly is This place. to take containment 50.1 presently contained to 50.5 contained presently are events all which for losses, demand for frequency of 49.9 of frequency Hz, this leaves only 0.4 only leaves this Hz, Slow Progression t e t t e t e t t e Gone Green Hz), the same is not true true not is same Hz), the Hz (0.7Hz Hz for the the for Hz Hz (0.4Hz Hz from an initial initial an from Hz Hz rise rise Hz
92 Chapter three 93 Since frequency response is procured in procured is response frequency Since advance of any event, the costs of holding more of duration entire the for increased are response the system conditions that require it, not just for fault. the after time of short period relatively the e
MW generation loss GW of demandGW MW of response is GVA.s of systemGVA.s inertia.
MW of response containing a loss GVA.s or 200GVA.s MW on a system with 20
GVA.s, whichGVA.s, also results in an overshoot
te ert a e e e e re e re e or underdamped response. response. underdamped or and 150 It also shows how 590 to reduced is inertia system when required 100 Frequency containment simulation of 500 Figure 3.25 of 500 Response performanceResponse frequency and high is inertia system When moves relatively slowly, the existing services are adequate contain to frequency. Figure 3.25 shows 365 2016 November Framework Operability System Chapter three Frequency management by 210 200 with requirement remains the same for simulation 600 by 100 loss generation the of size the Figure 3.26 shows the of effect increasing System OperabilityFrameworkNovember2016 e e re e Frequency containmentsimulationof600 Figure 3.26 te ert a ert a te MW. As recorded in Table 3.2, the response Table response in 3.2, the MW. recorded As MW for that with 150 with that for MW GVA.s of system inertia. It increases increases It inertia. GVA.s system of
GVA.s and most most GVA.s and MW to to MW MW generationloss e e compared to the movement of frequency. combined with slow speed of the response delivery, and measurement between lag the of Thedynamics. oscillatory behaviour is a result the latter of which results in unacceptable by 705 notably MW for that with 100 with that for MW GVA.s, GVA.s, 94 Chapter three 95 MW
MW is eroded. e a e a er e r eter a a p e p e te r eter te ert a 600 1285* 575 365 Hz Hz. TheHz. effect of this starting frequency is to
The mixture of continuous and set-point services is discussed in thenext section Frequency– regulation. Figure shows 3.27 an example of a 1000 contain to available response the of some erode the imbalance; in this case 170 generation loss with an initial frequency of of frequency initial an with loss generation 49.9
Generation loss (MW)Generation loss 500 (MW) requirement Response 590 365 365 e e MW generation loss being contained to 49.5
100 150 200 System inertia (GVA.s) inertia System r Example of 1000 Figure 3.27 SOF does not define the need for any particular service. Instead, we model a total response envelope, which could be delivered any by services. of suite designed appropriately frequency contain to optimised is response The theto relevant limit, given a number of system assessments, these In service parameters. and modelled is response dynamic continuous only in order simplify to the variables being modelled results. the of interpretation facilitate and Table 3.2 Table 3.26 (*unstable) for examples in Figure 3.25 and Figure Frequency response requirements 2016 November Framework Operability System Chapter three Frequency management shows how the maximum demand loss that can can that loss demand maximum the how shows 3.28 Figure response. the in time lag of effect the relationship between system and inertia the test can we frequency, high for 3.27 but Figure in shown as definition response asimilar Using System OperabilityFrameworkNovember2016 e Frequency containmentsimulationof600 Figure 3.28 a
a a te ert te ert MW generationloss a system inertia. system of levels higher and times lag shorter with contained be can losses Larger times. lag of avariety and 4s of time aramp with by aservice 20 with asystem on contained, be GW demand, GW demand, 96 Chapter three 97
necessary. Levels of response that would requirement that would otherwise be lead unacceptable to system dynamics are not included. not are e er t a a MW are contained a lower to Hz), reducingHz), the response
a
e e e e Figure 3.29 with a 4s ramp time and various lag times Requirements for response Figure 3.29 shows how the response response the how shows 3.29 Figure size loss generation with increases requirement and lag duration. Note that generation losses greater than 1000 frequency (49.2 2016 November Framework Operability System Chapter three Frequency management e e Requirements forresponsewitha1slagtimeandvariousramptimes Figure 3.30 requirement increases with generation loss size Figure 3.30services. shows how response ramping slow with occurs effect A similar System OperabilityFrameworkNovember2016 ra p
ra p ra p e er t e er t are not included. dynamics system to unacceptable lead would that response of Levels duration. ramp and 98 Chapter three 99
Hz. MW static Hz.Conversely, if the
r a Hz in this case). The 400 containment strategy but there is an underlying requirement for some continuous services for frequency regulation. Figure shows 3.31 a real frequencytrace over a period of 30minutes and the modelled performance of the system if the holding of increased is response dynamic continuous being difference the with decreased, or exchanged with a set-point static response response dynamic the if that shows It holding. response static and increased is holding volatile less is frequency decreased, holding and remains closer 50 to response holding is transferred from dynamic response is greater than the imbalance at that time so frequency quickly rises 50.1 to This is a disruptive and unacceptable action, which leads the to requirement for a minimum part as response dynamic continuous of level requirement. response total the of to static, frequencyto variation increases. Ultimately, this would allow frequency reach to response static the of frequency trigger the (49.8 Hz)
Hz,and
re e re e Negative value means dynamic to static exchange. Positive value means static to dynamic exchange. Figure 3.31 showing the effectFrequency regulation performance over 30 minutes of exchanging dynamic and static response Frequency regulation Frequency the in variation second-by-second The demand and generation between difference change. continuously to frequency causes This persistent variability is balanced by frequency response services that act regulate to frequency in normal operation, or ‘pre-fault’. services vary response dynamic Continuous frequency, with proportionally output their a at triggered services are set-point while fixed frequency level, forexample 49.7 and are therefore only used occasionally. Set- point services are used aspart of a frequency respond with either fixed quantity (known as a response. dynamic a with or response) ‘static’ to suited particularly services are Set-point set-point because providers, response demand static services can be provided switching by loads on or off, and set-point dynamic services can be provided equipment by that can vary The necessary. when appropriately, load its trigger frequencies for set-point services are set outside of the normal operation range (±0.2 2016 November Framework Operability System Chapter three Frequency management that use definitions of minimum performance performance minimum of definitions use that services response frequency existing The requirelosses faster response services. demand and generation of magnitudes Reducing system and the inertia increasing Conclusions System OperabilityFrameworkNovember2016
the purpose of frequency regulation. for response dynamic for arequirement also is there afault, of event the in frequency to contain In addition to frequency response requirements requirements. response of frequency review asystematic of part be should Code Grid the in
100 System Operability Framework November 2016 101 System Operability Framework November 2016 101 Chapter four
Voltage management 102 Chapter four Insights 4.1 Voltage management System OperabilityFrameworkNovember2016 system strength islow. may notbeabletoidentifyfaultswhen Existing networkprotection approaches transmission demandislow. to closeorwhere itisunlikelytorunwhen occur inregions where large plantisdue The largest decreases insystemstrength voltage control occuratthesetimes. The greatest requirements foradditional synchronous generationisrunning. lower andmore variablewhenlimited Regional systemstrength willbe
a disturbance. voltage containmentandrecovery after daily reactive loadprofile andensure must bedynamicinorder tofollowthe control resources, agreater proportion Of thegrowing requirement forvoltage are large andvolatile. is required inregions where powerflows volts. Additionalreactive powergeneration required inmostregions tomanagehigh Additional reactive powerabsorptionis
102 Chapter four
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When power flows are large, electricity networks tend absorb to reactive This power. means that generation power reactive of sources additional are required maintain to voltages at the correct level. When power flows are small, electricity networks tend generate to reactive power. sources additional that means this Conversely, of reactive power absorption are needed. Consumer demand can also generate or absorb reactive This power. depends on the type of load and its behaviour. Reactive power the throughout fluctuates continuously demand day according consumers’ to needs and must Distribution real-time. in met continuously be systemvoltages are largely dependent on the transfer of reactive power from the transmission system addressto imbalances, as there are reactive of sources controllable typically fewer networks. distribution the within power Voltage can be visualised as the water level in a tank. are used Taps regulate to thewater level maintaining by a constant flow in and out of the tank. The taps that flow in represent reactive power generation. The taps that flow out represent reactive power absorption. will tap each technology, the on Depending contribute may Some capabilities. different have a large flow and others contribute a small flow. changes to respond automatically can Some others whereas immediately level water the in gradually open can Some slowly. respond whereas others can only be fully on or fully off. A single tank has been shown for simplicity; thehowever, whole system could be visualised which tanks interconnected of number a as regions. and levels voltage different represent The three stages refer the in to Figure 4.1 management voltage of aspects different which have been assessed. been have which
. 2 . This at at 400kV is ±5% and ±10%
1 Grid Code: http://www2.nationalgrid.com/UK/Industry-information/Electricity-codes/Grid-Code Code: Grid http://www.dcode.org.uk/the-distribution-code Code: Distribution Voltage is a localised property of the system one vary from requirements that means which region another. to These requirements are determined the by configuration of the local and generation of behaviour the and network demand in that part of the network in real-time. Active power (measured in MW) provides consumers with their energy needs supplying (e.g. a kettle heating element boil to water). Reactive power (measured in Mvar) is required transfer to balance The network. the across power active of reactive power must be maintained in each region so that transformers, overhead lines and cables can move active power from the point of generation demand to efficiently and safely. of balance localised the on depends Voltage Reactive demand. and supply power reactive and voltage increases generation power voltage. decreases absorption power reactive Reactive power can be generated or absorbed networkby elements, generators and demand and characteristics electrical their on depending phenomenon, local a is voltage Since behaviour. reactive power is most effective for voltage imbalance. of region the to close when control the Distribution Code Distribution the lower transmission voltages. The ranges for for ranges The voltages. transmission lower distribution networks are similarly defined in 1 2 What is voltage management?What is voltage transfer management the facilitates Voltage 4.2 of active power economically, efficiently and distribution and transmission across safely controlled be must levels Voltage networks. margin operational acceptable an within system. whole the across The transmission system is operated so normal the within remain levels voltage that operating ranges defined within the Grid Code 2016 November Framework Operability System Chapter four Voltage managementwatertankanalogy Figure 4.1 Voltage management System OperabilityFrameworkNovember2016 5. 4. 3. 2. 1. Key 5 5 4 4
3 3 2 2 2 Protection 1 1 1 8. 7. 6. 8 8 7 7 6 6 2 2 8 1 1 1 generation and absorption. reactive of levels the by changing power reactive of imbalance the addresses action low. This level without rising too high or remaining too water original the to restore can they as quickly as flows their alter must taps remaining The separated. been now has network the of portion available taps available has changed, as a of configuration to The recover. tank the of remainder the in level water the allows This tank. the of rest the from hole the isolate to activated been has system A protection (post-disturbance) Voltage containment and recovery triggers the operation of a protection system. and voltage in fall the arrests generators the from current reactive The tap. ‘Generators’ the inherent overload capability – represented by by synchronous generators which have an provided presently is capability This period. this during drop rapid the to arrest able are (FFCI) injection current fault fast of sources Only flows. need to respond quickly and change their taps dry, running from tank To the prevent rapidly. to drop level water the causing tank, the in by ahole represented is which occurs A disturbance such as an electrical fault (disturbance) operation protection and dips Voltage addressed. quickly be may and impact less have will level water to the disturbances sudden where system a strong taps which can respond quickly represents generation or absorption. A large tank with elements all contribute reactive power Generators, consumer loads and network maintained. is level water overall the tank, the of out and in flowing water is there While Voltage (steady regulation state)
104
Chapter four
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It is typically measured short by circuit level (SCL) which is sometimes referred as to fault current. SCL is indicative of the amount of reactive fast provide can which generation dip. voltage a of timescales the within power From theisolation of the fault through full to recovery, a range of different capabilities are dynamic comprises This immediate required. dynamic slow support, dynamic fast support, support and switching of static elements. We containment for assessed requirements have and recovery needs at a number oftimes in our reactive power tank analogy with reference system to strength, as outlined in to requirements The section. following the manage each of these system conditions have been assessed across a ten-year period for each of the future energy scenarios. We haveWe assessed these timeframes in our analysis. This is important for the safe owners’ network of operation stable and and network users’ equipment. Given that frequencyand voltage disturbances are often recovery frequency that ensures it concurrent, can also take place effectively. System strength is an indication of the system’s disturbances. voltage to robustness inherent components. these of each to refer which has chapter Management Voltage The assessments our that such structured been conditions system the of each to correspond and demand disconnection. Historically, much much Historically, disconnection. demand and of this capability has come from the inherent synchronous capability of overload dynamic machines. Themost common form of disturbance is an electrical fault. Protection systems are designed detectto and isolate typically within fault, system transmission a level. voltage transmission a at 140ms Once the disturbance has been isolated, the priority is recover to voltage 90% to of normal operating levels within 500ms. Full recovery thereafter seconds, 30 by occur should compensation static by complemented actions. regulation normal and switching
voltage control devices can modify can devices control voltage voltage control devices provide a fixed offset in reactive This power. includes network and reactors shunt as such components can They capacitors. switched mechanically To manageTo voltage, we use a mixture of static devices. control voltage dynamic and Static be represented as taps which can only be fully on or fully off in the water tank analogy. Dynamic level voltage the to according behaviour their and provide a variable amount of reactive Theypower. can be represented as taps which can change their flows in response a disturbance.to The range of capabilities within the broad definition‘dynamic’ of is very diverse. Some devices can change their waiting without immediately contribution Mvar for a measurement delay. Others rely on a speed The response. a trigger to measurement of this response ranges from fast slow. to include devices control voltage dynamic Typical static compensators, synchronous generators, and (STATCOMs) compensators synchronous static var compensators Sufficient (SVCs). contain to critical is control voltage dynamic and recover the voltage following a disturbance, as well as manage to changes in the reactive power demand in real-time. transmission the on disturbance a Following system, it is critical that the disturbance is contained and the system remainssecure. Many disturbances cause both frequency and voltage deviations. For example, a generator fault which causes the loss of both active and reactive power would cause a system-wide frequencydip and a local voltage dip. Other disturbances, for example the inadvertent opening of a shunt reactor circuit, could cause a voltage disturbance with little effect on frequency. system be must capabilities control Certain voltage held in reserve during normal operation so that they can provide a dynamic response when a disturbance occurs. This prevents could which imbalance of state prolonged a generation widespread or instability to lead 2016 November Framework Operability System Chapter four Illustrative voltagemanagementrequirements Figure 4.2 Voltage managementtopicmap Table 4.1 Topic map 4.3 Voltage management System OperabilityFrameworkNovember2016 Recovery Containment and Voltage Protection and Dips Voltage Voltage Regulation System Strength Assessment r u o
o
e erate ar a r e ar ea t e p er ea t e ea t e p er ea t e ro o o ur and static elements for recovery. for elements static and containment voltage for power reactive dynamic for needs post-disturbance the of Assessment approaches for the future. existing of suitability and injection current fault fast and systems protection existing of assessment An profile. voltage steady-state the manage and follow to required resources power reactive dynamic and static the of assessment An assessments. capabilities that the affect other voltage management dynamic indicates which SCL of assessment An Description o o o ur o ur r o r
r u o o 136–139 128–135 116–127 111–115 Pages e 106 Chapter four
107
,
flexibility case B consistently flexibility case A is more reflective of providers of flexibility in flexibility case B this case reduces the number of large voltage for available machines synchronous requirement. overall the elevates support which been has which case the of Regardless studied, the results are indicative of the regions where requirements are likely be to highest in the future and the relative differences in need across different areas of the country. by conventionalby BMUs in the future. Nor would it be credible study to flexibility case C the requirements also refer a flexibility to case B assumption. alternative the of portion large a Since of application the non-synchronous, are is met conventional by BMUs. The other 50% comes from alternative sources in detail in the Balancing and flexibility section of the document (Chapter 2). While approach,today’s it would not be reasonable assumeto that all flexibility needs will be met where no flexibility requirements are addressed conventionalby plant at all. have We therefore studied noted be should also It topic. the throughout is a modelledthat year 2016/17 therefore Flexibility case B case Flexibility areas. assessment all in is where 50% of our reserve requirement such as energy storage and demand-side response. This flexibility case explainedis Throughout the Voltage Management Management Voltage the Throughout chapter, we have studied flexibility case B
.
and 4 3
explores the requirements is a characteristic of the Grid Code: www2.nationalgrid.com/UK/Industry-information/Electricity-codes/Grid-Code/ Code: Grid www2.nationalgrid.com/UK/Industry-information/Electricity-codes/System-Security- Standards: Supply of Quality and Security and-Quality-of-Supply-Standards/ This ensures that the system is secured for fluctuations in reactive power demand during normal operation. It is achieved from a mix of devices. compensation dynamic and static Voltage dips and protection explores the requirements manage to disturbances on the standards and codes Operational system. to equipment protection require implicitly detect and clear faults effectively. Reduction in minimum fault levels drives a need find to increase or approaches protection alternative alleviates also which injection current fault fast regional outlined have We dips. voltage assessments of protection and fault current required maintain to existing approaches. recovery and containment Voltage explores the requirements manage to post- action protection from voltage, disturbance through full to recovery. This ensures that voltage can be restored and disturbances do not propagate. A mixture of static and dynamic requirements are expressed in dynamic immediate an to relating timescales slow a response, dynamic fast a response, responses. static and response dynamic Security and Quality of Supply Standards 3 4 Figure 4.2 summarises the interaction of of interaction the summarises 4.2 Figure our voltage management topics on a voltage voltage a on topics management voltage our system that noting timeline, disturbance an has which characteristic a is strength impact across all areas. strengthSystem measured conventionally is which system SCL.by It is indicative of the dynamic for critical are which system the of capabilities voltage management. There are currently no explicit requirements for the system operator maintainto a minimum short circuit level or for the wider industry provide to this capability. regulation Voltage manageto steady-state voltage, in accordance Code Grid the in outlined criteria the with 2016 November Framework Operability System Chapter four Total voltage managementrequirement(NoProgression) Figure 4.3 of confines the within examples regional all to present practical not is it Since timeframe. analysis ten-year the across explored been have trends 11 where into down regions broken is requirement system total The approaches. protection existing to retain needed injection current fault fast of kA equivalent the expressed and needed is the regions where a review of protection devices identified have we protection, and dips voltage For described. is need system atotal where have been calculated regionally and combined generation or absorption. The requirements power reactive of Gvar in expressed are requirements management voltage the of Most requirements and Consequences 4.4 Voltage management 5 System OperabilityFrameworkNovember2016 SOF website: www.nationalgrid.com/sof
u r r
r u o o
u r ro o urr o urr o f u
u r r
power generation. and positive values correspond to reactive correspond to reactive power absorption values Negative fault. the after 30s and 500ms 300ms, 80ms, at time in snapshots of series a into down broken been have requirements the least and most change. Post-disturbance scenario) in Figure 4.4, which respectively show Consumer4.3 Power and No for Progression below shown is 2016/17, for requirement 2025/26 2020/21 and management voltage total the of A summary appendix on our website our on appendix adata as available are areas all in analyses our of outcomes full the document, this o o r o r o o 5 . (the most change in Figure
108 Chapter four
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Gvar, occurringGvar, – the highest highest the – . This rises to o Gvar in 2024/25, occurringGvar in 2024/25, r o r o o o a high of 16.9 Power Consumer summer in in the analysis period. period. analysis the in The requirements across a disturbance become need a is There pronounced. increasingly review to owners network transmission for protection approaches in light of falling minimum regions majority of The levels. short circuit are affected in all scenarios The 2020/21. by scale of impact will require the modification of fast increase to action or approaches protection fault current injection retain to the effectiveness of existing devices. The latter would also help arrest to local voltage dips and mitigate propagation of disturbances across the system. in winter Power Consumer largest reductions in conventional generation generation conventional in reductions largest capability. control dynamic and capacity voltage daily that show assessments The variable increasingly become needs regulation renewable as conditions weather to linked and a drives This grows. generation distributed significant increase in the component of voltage either be must which state steady in regulation The switch. automatically to able or dynamic isgreatest 10.0 need in 2016/17
u r r r u r shows the the shows shows the least the shows f u o o urr o
ro o u r u r
o r u o
u r r r u r greatest requirement and fastest rate of change. Reactive power absorption needs are reactive increased by driven predominantly power exchanges at the interface withthe distribution systems and the reactive power Periods networks. loaded lightly by generated reduce output generation distributed high of which flows power cross-system traditional where regions Some effect. this emphasises power flows are volatile show an increased requirement for both reactive power generation absorption. and management voltage for available resources The transmission where periods at diminished are synchronous of Closures low. is demand system diminishes the running reduced and plant the of capability management voltage overall system. This is particularly noticeablein areas the see which infrastructure. heavy network of Across all scenarios, the need for reactive power absorption and sufficient fast fault current injection arrest to voltage dips increases over time. Progression No requirement and the slowest rate of change over ten years. Power Consumer Figure 4.4 Total voltage management requirement (Consumer Power) Total 2016 November Framework Operability System Chapter four for active power. Across all scenarios, there there scenarios, all power. Across active for demand system transmission the than greater is power reactive for demand system transmission ten-year timeframe, there are periods where the the of Towards end the high. are requirements as does the number of periods where all voltage management assessment areas The scale of requirement increases across 2025/26. by dynamic 2016/17 to be required is 78%–84% and in dynamic be required is 55%–68% need, compensation. Among the total reactive power dynamic of levels maximum the for need Post-disturbance requirements drive the Voltage management System OperabilityFrameworkNovember2016 transmission demand for active power. active for demand transmission power during support these periods of low reactive dynamic economical more of providers for aneed is There means. by alternative met be cannot requirements if merit of out are they by running conventional generators when to intervene have therefore will operator system the requisite voltage control capability. The to provide system transmission the on running generation insufficient is there where times are 110 Chapter four
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and minimum and 6 Regarding minimum SCL, the Grid Code specifies that generators and voltage source converters must ride through faults and contribute the maximum fault current that their capabilities allow during the fault. If SCL is too it canlow, result in a dynamic performance deficit during a fault and consequential operation. protection network in challenges varies SCL to contribution Generation Synchronous technology. on depending times 5–7 between typically deliver machines operation, normal under supplied current the otherwise described as 5–7 per unit (pu) of with time around to DFIGs 2.5pu. (Doubly Fed 1.15– typically deliver Generators) Induction contribution This current. fault initial of 1.25pu typically drops rapidly approximately to 1pu which can be sustained up 100–140ms to initial fault current. This contribution decays decays contribution This current. fault initial after thefault. The values of maximum SCL reported in the Statement Year Ten Electricity SCL reported inthis document are based on the detailed planning data provided in Code. Grid the with accordance
Electricity Ten Year Statement: http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/Electricity-Ten-Year- Statement: Year Ten Electricity Statement/ 6 Background characteristic regional a is strength System which can be expressed as short circuit level measured(SCL), in kA. It provides an indication of the local dynamic performance of the system disturbance. a to response in behaviours and The primary contributors of SCL todayare large synchronous generators. SCL is often also referred as to fault current. Since SCL on dependent highly is it metric regional a is current fault their generators, of locations the delivery with current fault and contribution network transmission For time. to respect operators network distribution and owners System strength is low during periods of low transmissionSystem strength during periods low is low of large demand synchronous generators because system fewer SCL is an important marker for regional network performance across a range of criteria. management voltage The Grid Code, Distribution Code and SQSS do not have an explicit requirement for a minimum or a maximum level of SCL; however, it is implied other by performance criteria synchronous for ratios short circuit as such synchronous large of amount the As generators. plant on the system declines, there is an increased need for this dynamic performance from other sources. 4.5.1 System strength Assessments 4.5 run these at all times scenarios. in 2016 November Framework Operability System Chapter four load and generation within distribution systems. of representation the for recommendations flexibility case Bdispatch case flexibility the to relate applied for every settlement period, an algorithm was study network afull to perform practical not was it Since patterns. demand and dispatch results were then linked to regional generation and minimum demand conditions and the to maximum according chosen were points of number Agreater approach. year’s last with consistent studies point cardinal of a series Regional SCL was calculated based on Results Voltage managementassessmentregions Figure 4.5 Recommendation G81 Engineering ENA on based are values These Voltage management 8 7 System OperabilityFrameworkNovember2016 International Electrotechnical Commission: https://webstore.iec.ch/publication/24100 documents/G81/ENA_ER_G81_Part_4_Issue_2_Amendment_1_080109.pdf ENA Engineering Recommendation G81: http://www.energynetworks.org/assets/files/electricity/engineering/engineering%20
th e t a e t a th a e a 7 and IEC60909 rth a e e t a rth e t a 8
Figure 4.5. SOF in analysis the with a regional basis. The regions are consistent on performed been has SCL of analysis The in in the in late quite until occur not does change This years. future in decrease will levels minimum that show figures The period. settlement any level across the whole transmission system for SCL lowest 4.7 the show Figure 4.6 and Figure against the cardinal point studies. benchmarked region, each for profile SCL a year-round to create variation SCL to regional rth t a Consumer Power No Progression th t a a th a t rth a t a a t a reater reater a t a scenario, but quickly very . 2015, as outlined in in 2015, outlined as
112 Chapter four 113 u or u r u u or u r u
r of r o u o r of r r of r o u o r of r Figure 4.7 Lowest SCL across all regions (Consumer Power) Figure 4.6 Lowest SCL across all regions (No Progression) Lowest SCL across all 2016 November Framework Operability System Chapter four investigated at further a regional level. when evident is which demand system synchronous generation and low transmission non- high of to periods due is This SCL. decreasing of trend ageneral show also They Regional rangeofSCL(SlowProgression) Figure 4.8 distinct trends: Figure 4.6 and Figure 4.7 show two Voltage management System OperabilityFrameworkNovember2016 synchronous generator output is also high. large and high remains demand where to periods due lower is decline of rate the however, declines; also system the across SCL minimum the of value maximum The synchronous generation. non-synchronous generation relative to of output in increase relative to the due time with rapidly drops SCL minimum The or r u t a rth
t a th a a
a a t
a e rth for this year’s studies. year’s this Bfor case flexibility of application the and year this approach in changes to the due exceptions some are there though reported, previously to those equal or than greater are SCL minimum in declines the SOF in reported The regions show similar trends to those for region each in SCL minimum absolute the and maximum absolute the between range the show figures These SCL. of characteristics Figure 4.8 and Figure 4.9 detail the locational Slow Progression a a e a e a 2015. In the majority of cases, cases, of 2015. majority the In and Gone Green and a a t reater a .
114 Chapter four 115
a reater a t a , North Wales is notable a a e a No Progression No In for an increase in minimum SCL due the to proximity of new synchronous developments. While Figure and 4.8 Figure note the 4.9 maximum and minimum SCL, it is important to note that the distribution within these ranges is There year. the throughout variable increasingly is a trend towards lower values more often, synchronous of patterns running the to related shutdowns station periodic Notably, generation. our modelled in are (which maintenance for flexibility case) often coincide with the periods network transmission Since level. fault lowest of could this modelled, been not has maintenance similarly deplete the strength of the network. Conclusions SCL becomes more dependent on the large of number decreasing a of behaviour assessment the Across units. synchronous period and scenarios, the North West and West see West South and Midlands East Midlands, the greatest decline in minimum SCL. Across all is There increases. SCL in variability the regions, more time spent towards the bottom of the SCL range as the ten-year period progresses. rth a e )
a t
a
kA in kA in a a and in Consumer 84% ) by 2025/26. There 2025/26. ) by is th kA (in Green 2025/26 by Gone t a
rth . A similar pattern is observed in t a
r u or North West and West Midlands region by The2025/26. reduction in minimum SCL is Green in82% Gone Power plant synchronous large of regions other such as the East Midlands. This is due to running stations power conventional fewer to demand transmission due minimum at not being in economic merit. The region of lowest absolute SCL (in kA) is North West & West Midlands (0.7 Power Consumer economic in plant synchronous limited similarly merit in this region. In the South West there is an overall decline from of 72% 5.19 and limited is generation synchronous as very reaches generation non-synchronous levels. penetration high The trends in SCL are not consistent across all zones. The North Scotland and South Scotland regions experience limited change across the scenarios because there is less change to them. in generation synchronous of levels the The largest regional decline occurs in the the in occurs decline regional largest The 1.47 to 2016/17 Figure 4.9 (Gone Green) Regional range of SCL 2016 November Framework Operability System Chapter four Voltage regulation inGBtransmissionuptothetransmission/distributioninterface Table 4.2 day. the during quickly changes profile demand reactive the if switching automatic of capable or dynamic either be must requirement the of aportion that means This future. the in capability to transition to a different balance must be maintained in real-time, as must the of reactive power generation and absorption when the system is undisturbed. The balance limits within acceptable plant performance transfer power efficient facilitates This operation. levels within acceptable limits for steady-state Voltage regulation refers to maintaining voltage Background volatile power transfer. and heavy that experience in regions increase but must power to prevent generation low overall, voltages reduces for reactive need The in scenarios. all increase must To prevent voltages, high reactive power absorption Voltage regulation 4.5.2 Voltage management 9 System OperabilityFrameworkNovember2016 Scottish Hydro Electric Transmission Area. Voltage 400kV 275kV 132kV <132kV
Planning Limits ± 2.5% ± ± 5% ± ± 5% ± ± 5% ± the operational limits listed in Table 4.2. operation. Our assessments are based on accommodate the uncertainties of real-time operational criteria to ensure the network can scenarios. Planning criteria are stricter than design specific under limits planning to the networks their to develop obligated are owners network Transmission Code. Grid and (SQSS) Standards Supply of Quality and Security the voltage according to the operational limits in steady-state regulates operator system The Operational Limits Operational ± ± ± ± 5% (± 6% in North Scotland ± 5% (± North 6% in 5% 10% 10%
9
)
116 Chapter four 117
analysis assesses assesses analysis . Our SOF The requirement for reactive power support to boundary transfers is discussed in the Electricity Statement Year Ten rather requirements regional year-round than network boundary flows and remains process. this with compatible Over the past decade, the transmission system has experienced a growing need contain to transmission low of times at voltages high 4.11 Figure and 4.10 Figure demand. system show the historical changes in daily minimum demands. power reactive and active
o r o r Figure 4.10 Daily minimum active power demand (2005–2016) Voltage regulation is mostefficiently achievedby minimises This power. reactive of local sources losses from power transfer across the network voltage regional of possibility the reduces and instability. or excursions The most significant requirements have transmission peak of times to related historically demand, driven a need by support to large active power flows on the transmission Optimisationsystem. the network of therefore losses and minimising on concentrated supporting cross-system transfers with sufficient reactive generation capability. 2016 November Framework Operability System Chapter four a diverse range of controllable reactive power power reactive controllable of range a diverse in the Grid Code. Across technologies, there is specified are which users system transmission voltage relies on the capabilities provided by to regulate ability operator’s system The contributing factors: understanding that there are a number of within the industry; however, there is common understood fully not and complex are demand reactive in decline of causes exact The demand has decreased consistently. reactive minimum that show figures The Daily minimumreactivepowerdemandfrom(2005–2016) Figure 4.11 Voltage management 11 11 10 System OperabilityFrameworkNovember2016 distribution-connection-and-use-system-agreement-dcp222-non-billing-excess-reactive-power-charges Distribution Connection and Use of System Agreement DCP222 – https://www.ofgem.gov.uk/publications-and-updates/ Reports/ENA%20HVWG%20Report%20Final.pdf –http://www.energynetworks.org/assets/files/news/publications/ Report Feasibility Technical group: working Volts High ENA o r r the electrical characteristics of equipment. of underground cabling and changes in distribution networks due to higher levels Increased reactive power generation from rather than absorb reactive power. reactive absorb than rather to generate them causing systems, voltage higher the on flows power reduces This to distributed generation at lower voltages. Increased reactive power generation due consumer electronic loads. Increased reactive power generation from
designing future voltage control arrangements. when considered be will this colleagues, DNO low active power output. In coordination with or no at accessed be can power reactive particular, In generators. from power reactive to procure DNOs of ability the facilitate which 222 (DCP sponsored distribution charging modification aDNO on adetermination 2016, issued Ofgem 15 On August reform. regulatory or market longer-term on rely not do which term short the in identified options to deliver collaboratively for high voltage mitigation. We are working report 2016 the ENA released a technical feasibility April In regulation. voltage of forms new to develop industry the across continues Work synchronous machines. of characteristics inherent to the due synchronous technologies in this regard non- than capability and flexibility greater to provide obliged generally are generators generation and absorption. Synchronous 10 into options available across networks 11 ). This provides tariff changes changes tariff provides ). This
118 Chapter four 119 .
and Power Consumer No Progression No The results in Figure 4.12 and Figure 4.13 areThe and results Figure in 4.13 Figure 4.12 for arrangement. Negative values correspond to to correspond values Negative arrangement. values positive and absorption power reactive generation. power reactive to correspond o o r u o r u r r u o r o o o o r u o r u r r u o r o o
u o r of r u o r of r Figure 4.13 Total voltage regulation requirement (Consumer Power) voltage regulation requirement Total Figure 4.12 ) voltage regulation requirement (No Progression Total Results requirement regulation voltage total The expressesthe total support necessary across the entire system regardless of whether it is provided Balancing compensation, network-based by commercial another or participants Mechanism 2016 November Framework Operability System Chapter four Total voltageregulationrequirementenvelope(GoneGreen2016/17) Figure 4.14 Voltage management System OperabilityFrameworkNovember2016 to 24.1 No Progression to 25.0 to 24.5 in requirement generation Gvar maximum The in in requirement absorption Gvar maximum The 44.0 Consumer In Power decrease. loaded circuits. such as reactors and switching out lightly provided by current network-based solutions 6 approximately required, absorption power reactive the power. Of reactive of sources by other provided to be have would rest The compensation. capacitive current network-based solutions such as 16 approximately required, generation power reactive the Of No Progression o o r u o Consumer Power
r u r r to 25.1Gvar Gvar, an increase of 10.0 of Gvar, increase an Gvar across the period, a20.1 period, the across Gvar Gvar, an increase of 10.9 of Gvar, increase an pr
a Gvar, 18.9 an Gvar could be provided by by provided be could Gvar it increases from 14.1 from increases it drops from 44.6 from drops increases from 14.1 from increases Gvar could be be could Gvar Gvar decrease. Gvar Gvar. Gvar. In Gvar. In it drops from from drops it Gvar Gvar Gvar Gvar Gvar Gvar
Gvar Gvar
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network loading. highly volatile as it depends on transmission B case to flexibility refers requirements in Gone Green 4.14 Figure 2016/17 shows requirements, of envelope the describe fully to more order In system during low demand periods. operability challenges for the transmission makes voltage regulation one of the principal This system. transmission the on demand power active minimum the exceeds needed absorption power reactive maximum the Across all scenarios, there are periods where Consumer Power 2016/17, summer in requirements in range daily 4.15 maximum of day year. the Figure illustrates current the in B case flexibility to realise order 5.5 approximately of absorption power reactive in ashortfall leaves This demand. connected generation running at minimum transmission- by the absorbed be could 50% system conditions. 11 remaining the Of t and Table 4.3 describes the the Table 4.3 describes and Gvar, approximately Gvar, approximately e , the envelope is is envelope , the a . Noting that this this that . Noting e Gvar in in Gvar
ar 120 Chapter four
121 ar ther r u a a t ra e a a ther a a C a ra e a ra ar ar e r ta ta e re at re re e t re at ta e ta flexibility
r
ra ra ear ter e t r r o Figure 4.15 ) regulation requirement for 19/06/2016 (Consumer Power Voltage 2016 November Framework Operability System Chapter four power absorption. This occurs to such an an to such occurs This absorption. power reactive towards significantly shifts requirement 2024/25. Firstly, the whole voltage regulation 2016/17 in range and reactive greatest of day the between differences main two are There to 10 automatically would be required comparing equipment which could be switched in/out to 16.9 day, the of up middle the in dip the Across Consumer in Power occurs which in requirements in the assessment period range 4.16Figure maximum the shows Behaviours observedacrossthedailyloadprofile Table 4.3 Voltage management System OperabilityFrameworkNovember2016 20:00–00:00, GMT 20:00–00:00, Evening Late GMT 14:00–20:00, Pick-up Evening GMT 11:00–14:00 Afternoon Late Morning/ GMT –11:00 05:30 Pick-upMorning 00:00–05:30 GMT 00:00–05:30 Overnight Time Gvar for the 2016/17 the for Gvar case. Gvar of dynamic capability or static static or capability dynamic of Gvar
System Conditions capacitive, greater levels of reactive power absorption are required. are absorption power reactive of levels greater capacitive, more become networks As decreases. demand power Active transitions to domestic. Reactive power demand is more capacitive as commercial activity evening. the towards peak approaching increases, demand power Active with high solar PV penetration. areas to regionalised are changes demand power reactive and Active period. this of end the towards output maximum to increases PV Solar absorption need. Increased active demand decreases the reactive power on. goes morning the as up pick to begins generation solar Distributed absorption. reactive for need the decrease flows power increased The demand. power active supply to up starts generation Transmission capacitive. less becomes load and begins day working the as increases demand power Active to distribution network. power flows and increasing reactive power exchange from transmission Distributed generation increases network capacitance by offsetting low. also is demand power active system Transmission-connected generation output is low as transmission requirement. absorption areactive drive networks loaded lightly and demand Reactive flows. power system transmission low and demand power active Low 2024/25. 2024/25.
have to be met via dynamic or automatic means. automatic or dynamic via met to be have percentage of the regulation requirement will alarger increases, required absorption or generation reactive in change of rate the As reactance. the over dominates networks loaded lightly of susceptance the and of networks when solar PV output is high loading light to the due is This afternoon. the in requirement in drop fast and significant by a followed morning late the in starting requirement absorption reactive fast and power generation. Secondly, there is a large reactive for need any hardly is there that extent
122
Chapter four
123 ar ther r u a a t ra e a a ther a a C a ra e a ra ar ar e r ta ta e re at re re e t re at ta e ta flexibility
r
ra ear ter e t r r o Figure 4.16 regulation requirement for 02/06/2024 Consumer Power Voltage 2016 November Framework Operability System Chapter four Maximum zonalvoltageregulationrequirementsforallscenarios(2025/26) Figure 4.17 This highlights a broadly consistent increase in 4.17. Figure in scenario and by date shown is power generation and absorption requirements reactive maximum of breakdown regional The Voltage management System OperabilityFrameworkNovember2016 o r u o r u r r r re r re ree e t a rth
t a th a a e ree ree e C er er er C er a a t in generation. across all scenarios, with a greater volatility regional reactive power absorption requirement a e rth a a e a e r re r re a a a t reater a
124 Chapter four 125 scenario, the maximum reactive power the left, demonstrating the underlying increase the demonstrating left, the distribution the at generation power reactive in whole in increase an driving is which interface, system reactive power absorption. In the Gone Green similar supportgeneration remains requirement currentto levels, but for a significantly lower number of periods compared today. to o o r u o r u r r u o r o o
u o r of r Figure 4.18 Total voltage regulation requirement for Greater London (Gone Green) voltage regulation requirement for Greater Total We haveWe outlined a number of example regional regulation voltage total the of breakdowns requirement for regions of significant change. The range and volatility of requirements in Greater London are notable due the to volatility of high and low network loading in this heavily Requirements network. the of region cabled are illustrated There is in a shift Figure 4.18. to 2016 November Framework Operability System Chapter four Total voltageregulationrequirementforSouthEastEngland(ConsumerPower ) Figure 4.19 absorption requirement both increase. regions where the reactive generation and few the of one therefore is This flows. power growth in the region causes highly volatile of interconnection and distributed generation level high the because note particular of is area This England. of East South the in requirement Figure 4.19 describes the voltage regulation Voltage management System OperabilityFrameworkNovember2016
r of r o u
o o r r u o r u r Coordination topic. Distributed Generation within our Whole System from Support Voltage in outlined are area the alternative approaches to voltage control in ofdiscussion this region and associated Further time. 7% the of approximately 2016/17 exceeds levels generation Reactive by 2025/26. time 8% the of approximately level 2016/17 maximum the exceed requirements 2.9 of need absorption Consumer Power shows a maximum reactive reactive amaximum shows Gvar. Absorptive Gvar. Absorptive 126 Chapter four 127
Gvar of This area therefore experiences one of the largest differences in reactive generation and regulation, voltage for required absorption thehowever, range of volatility is decreased requirement additional An years. future in in this area for approximately 1.4 contributions network in variation as well as when active power loading ismore variable. a variability, within-day increasing to Due regulation voltage total the of proportion greater requirement will have be to dynamic or capable needs power reactive as switching automatic of day. the throughout change reactive power absorption is needed across scenarios.all
o o r u o r u r r u o r o o
u o r of r Figure 4.20 Total voltage regulation requirement for East Midlands (Slow Progression) voltage regulation requirement for East Midlands Total Figure 4.20 shows the voltage regulation regulation voltage the shows 4.20 Figure requirements for the East Midlands. By 2025, of the20% time is spent at greater reactive today. than requirements absorption power power declining sees Midlands East The transmission minimum of times across transfers synchronous where periods reduced demand, generation is running and a distribution system that predominantly exports reactive power. Conclusions There is a consistent increase in reactive power voltages high prevent to needs absorption time scenarios. More and regions all across is spent at a higher level of requirement than in The need for reactive power generation2016/17. reduces in most regions. These trends are demand power reactive changing by driven 2016 November Framework Operability System Chapter four for Generators (RfG) code (RfG) Generators for System Operators – Electricity) Requirements ENTSO-E (European Network of Transmission requirements with the implementation of the Code Grid to align underway currently are Changes fault. the after 140 to 3minutes ms 15% from 90% and between recovery and dip voltage of levels varying withstand also to must 140 up 0Vfor of They ms. voltage system atransmission to withstand networks connected to the transmission or distribution stations power large all requires Code Grid The is achieved by fault ride-through capabilities. latter The systems. by protection achieved is these of former The recovery. stable to facilitate system to the connected remains equipment that ensuring while cause the isolate to rapidly are priorities the disturbance, avoltage During Background system voltages. the fault during injection to support fault current fast with sufficient needed are approaches levels circuit decline. Alternative short protection as systems protection network reviewed be must Regional Voltage dips protection and 4.5.3 Voltage management 12 12 System OperabilityFrameworkNovember2016 dispatch made up by small-scale generation. 1 these requirements on generators as small as place could It delivery. of trajectory the and expected current fault maximum the injection, current fault before permitted time maximum with respect to voltage and time, such as the behaviour refined more a describe to is proposal Requirements for Generators (RfG): https://www.entsoe.eu/major-projects/network-code-development/requirements-for-generators/ MW due to the increasing proportion of the the of proportion increasing to the due MW
12 . The current current . The
a driver going into a tunnel in Figure 4.21. of analogy the using conceptually explored is idea low. This are voltages retained when system the from reference a finding difficulty have may devices These operate. to stably system the from reference waveform balanced a as well as voltage retained enough require used by some non-synchronous generators, Phase-locked loop (PLL) controllers, which are through a fault than synchronous generations. to ride adip during voltage retained a higher Non-synchronous generators require typically fault current injection. injection due to their characteristic immediate current fault fast of source predominant the are generators Currently, synchronous operation. protection facilitates also and afault through to ride failing generation of risk the to reduce helps This adisturbance. during dip voltage the arrests which current reactive (FFCI), injection current fault by fast supported is It disturbance. the through to ride a generator of ability the affects afault during voltage retained The
128 Chapter four 129
When the motorist approaches an obstacle which has not been accounted for in the route plan, the satnav will delay as it decides how respond. to In a power systems context, this is analogous a to as behave not might which controller PLL expected if unanticipated conditions arise for which it has not been tuned. When the motorist goes into a tunnel, they lose satellite coverage. Depending on the programming of the satnav it may cease to or information outdated to respond update, act based on a fixed behaviour(such tellingas the motorist keep to going straight forwards). This isequivalent a PLL to close anto electrical that low so is voltage retained the where fault there is little or no voltage information inform to response. its When the motorist comes out of the tunnel, the satnav will suddenly receive new information. There could be a delay whilst the in jump a be could there and updates satnav is This information. new this on based position equivalent a PLL to controller issue knownas “phase jumping” which can lead a delayed to to failure a or conditions new to response adequately. respond The control performance of a PLL controller controller PLL a performance of control The can be visualised as a motorist with a satellite navigation system. The motorist gets satnav the from route their about information array an with communication on relies which Much position. its triangulate to satellites of like a fast a satnav, and refined PLL controller operating its about much understand can system the polling on reliant is but environment for data so it can respond accordingly. 1. 2. 3. 4.
4 3 2 1 Figure 4.21 example Phase-locked loop controller 2016 November Framework Operability System Chapter four Impacts oflowshortcircuitlevel(SCL)onprotectionandcommutation Table 4.4 future years. of network equipment will require review in pieces these of more or one that low so are regions of the network where circuit short levels different the explore section this for results The Table in 4.4. outlined as and current source converter HVDC links, operation of network protection systems correct the for important also is it however PLL devices and non-synchronous generators; during a fault could the affect behaviour of The decrease in fast fault current injection Voltage management System OperabilityFrameworkNovember2016 HVDC Converter Source of Current Commutation Protection Differential Protection Distance Protection Overcurrent
ultimately disconnect. and block will convertor failure. commutation The to lead can it valve, next the across reversal complete before voltage valve or thyristor cannot If commutation across a trip. will relay bias current setting, the the to different is them between difference the If across a circuit or zone. infeed and outfeed current the Compares trip. will relay the impedance, reach the than lower is measured impedance the If impedance. reach the with point relay the at impedance Compares the trip. will relay the setting, the than higher is current the If threshold. afixed to current the Continuously compares Operational Principles
convertor. the of rating the 3 times than lower MVA is in SCL approximated as when risk can generally be however, specific; plant commutation failure is to Resilience unbalanced faults. be more sensitive to which may possibly overcurrent setting, 12% to up is of setting bias A typical intended. is disconnect more than and reach” “over not does protection the that ensure to 20% to up of margin Typically set with a circuit. the of loading current continuous maximum the 1.5 times 1.2 and between to set Typically Design and Setting protection drives the requirement. the drives protection distance where examples limited also are There protection system on the transmission network. aback-up as used usually is which protection, of cases, requirements are driven by overcurrent synchronous generation decline. In the majority significant of regions in particularly fall, levels fault as future the in required be will review aprotection that imply results The respectively. risk in No in Progression risk at be could devices protection above the of the per region percentage of time where one section. Figure 4.22 and Figure 4.23 depict strength system the in outlined is Level) Circuit (Short SCL regional of breakdown full The Results
generator availability. and local synchronous configuration by network challenging, influenced ratio becomes more requisite short-circuit maintaining the As SCL declines, currents. off-peak and peak both for accordingly set be must bias The does not operate. relay the that small so be may between difference the flow, current low of times At significantly. vary injections fault if lead to complexities circuits, this could current. Across complex to voltage of ratio the decline in SCL retains the provided effect No is acceptable. than slowly more far operating or SCL, low at all at triggering not This protection risks Circuit Level Circuit Short Low of Impact and Gone Green and
130
Chapter four 131 ear at r ear at r e ree e r re ear at r ear at r e ree e r re ear at r ear at r e ree e r re
ear at r ear at r Figure 4.23 Gone Green) Areas in need of protection operation review ( Figure 4.22 operation review (No Progression) Areas in need of protection 2016 November Framework Operability System Chapter four East Midlands–SCLandprotectionrisk(NoProgression) Figure 4.24 website our via appendix region, the full datasets are available as an every for result assessment full the include in England of East South the for same the shows East Midlands in No Progression across levels SCL minimum in variation for results of breakdown full 4.24 the shows Figure Voltage management 13 13 System OperabilityFrameworkNovember2016 SOF website: www.nationalgrid.com/sof Gone Green
r of r o u
. Since it is not practical to to practical not is it . Since 13 . a p t r
r t t u or r u r u u or a e t . Figure 4.25 e
p a t r
r e t e t r large change in this region. this in change large least reduction scenario, demonstrating the penetration is high. No Progression of Scotland where non-synchronous generation North the and England West South of outside system transmission current the in anticipated usually not to levels falls region this in SCL minimum The decline. SCL of regions significant most the of one is area Midlands East The rre t
is the the is 132 Chapter four 133
t rre intact system conditions. Commutation Commutation conditions. system intact link converter source current the of function may be impacted in future years, subject to the availability of the large generator. Notably, outage long on modelled was generator this in the summer when the of 2021/22 risk of occurs. failure commutation r e t t e r
r t a p
e e t a t t u or u r u r
r t a p t r
a t t a C
u o r of r Figure 4.25 and protection risk (Gone Green) South East England – SCL Figure shows 4.25 the results for South East England area. This region is heavily dependent on a limited double circuit corridor and the synchronous large single a of availability which region a in provision SCL for generator is otherwise highly non-synchronous. Across Across non-synchronous. highly otherwise is overcurrent curve indicates the scenarios, all and limited distance protection risks under 2016 November Framework Operability System Chapter four Additional fastfaultcurrentinjectionforprotectionoperation(2020/21) Figure 4.26 2025/26 2020/21 against for and scenario and region each for shown are results The compromised. be not would devices protection existing where to alevel current fault lowest the to increase required injection current fault fast of Figure 4.26 and Figure 4.27 show the amount Voltage management System OperabilityFrameworkNovember2016
f f u urr o t a rth r re r re ree e
t a th a a e ree ree e C er er er C er a a t
a e rth magnitude of change compared to 2016/17. compared change of magnitude high the for notable are regions Midlands East the and Midlands West and West North the with the other voltage management topics, a Gone Green a a e a e r re r re a 2016/17 baseline. Consistent a a t reater a 134 Chapter four
135 a reater a t a a r re a e a As short circuit level declines, it is also necessary ensure to that generators are able to rideto through voltage dips at both transmission strength system when voltages distribution and conventional As low. is voltage retained and sources of fast fault current injection reduce, as critical more become will requirement this voltagedips are likely increase to in depth. rth a e a t a C er er e ree a a th t a
e ree e ree r re rth t a
f f u urr o o urr f u f Conclusions There is a need review to regional protection systems and the commutation of current source converter HVDC links as fast fault the throughout decreases injection current function, protection to respect With period. there is a clear requirement for a more focused investigation overcurrent of protection devices specifically, which are commonly used as system. transmission the on protection back-up Some regions, for example East Midlands and South East England, show a need consider to term. longer the in operation protection distance failure commutation for assessments the Since were performed on an intact network, network patterns running plant regional and outages could significantly affect short circuit level and risk. failure commutation the Figure 4.27 Additional fast fault current injection for protection operation (2025/26) Additional fast fault current 2016 November Framework Operability System Chapter four considered balanced three-phase faults. only have we awhole, as topic management voltage the with keeping In ms. 300 within to 1.3 less or pu decline and 2pu than more to no limited be should phase any in Electrical Standards, temporary over voltage Relevant the Under voltage. over temporary limit to and through ride fault for voltage retained sufficient to ensure need by the driven are In these two initial timeframes, requirements recovery. voltage support can controlled switching of static elements s, ms–30 500 From support. provide can responses dynamic slower ms, ms–500 300 In proportionate response to the voltage deviation. and fast be should delivery power reactive window, time ms ms–300 80 the In system. to the coupled inherently be must delivery power reactive window, ms 0–80 the In cleared. been has fault the after (static) s 30 and dynamic) (slow ms 500 dynamic), (fast ms 300 dynamic), (immediate ms 80 at snapshots of aseries into down broken been devices. Post-disturbance requirements have static and dynamic of by amixture achieved be has been isolated. Voltage recovery can then disturbance the after power reactive in deficit or asurplus from arises This voltage. under or over generation or absorption needed to contain the power reactive the of terms in expressed is It acceptable levels following protection operation. to voltage to return required power reactive dynamic sufficient requires containment Voltage Background by generators. synchronous overload the dynamic complement provided capabilities reactive power Additional dynamic to isrequired Voltage recovery and containment 4.5.4 Voltage management System OperabilityFrameworkNovember2016
data appendix data each region are therefore available as an online for datasets and curves full The document. this in reader the for effectively information this to present possible not is it absorption, and per region for both reactive power generation frames time five are there that Given s. 30 and ms 500 ms 300 ms, 80 of timeframes snapshot the at view year-round the of a breakdown provide results full year. the Our across change current operational requirements as they and needs reinforcement network future of analysis against requirements power reactive We have validated our post-disturbance strategies and fast automated responses. window through alternative operational ms a300–500 within achievable be may Subject to individual cases, more rapid use cleared. has fault the if to see action reclose auto delayed after disturbance, the safter 30 least at until occur normally not would resources of static switching Currently, automatic effect. too quickly, which could have a destabilising implemented not is response static that ensure to assessment by case to acase subject be would approach This recovery. voltage overall to support manner acontrolled in resources could be automatically switched static swindows, to 30 ms 500 the In by generators. delivered be can to voltage relative generation power active proportionate that stabilised sufficiently be should disturbance fault ride-through requirements, where the studied because it aligns with Grid Code voltage deviation. This time frame has been wholly dynamic and proportionate to the reactive power response must remain clearance, fault of a ms 500 first the Within are presented below. presented are 14 and only the summary results results summary the only and
136
Chapter four
137
a reater a t a a t a a a e a rth a e The results show the total post-fault reactive power requirement, inclusive of voltage regulation. therefore have also We presented show clearly to requirement regulation the the dynamic requirement above these levels. levels. these above requirement dynamic the a t a tat tat
e ate a a a and 2020/21 . th t a
rth t a ta e re at re at ta e a
o r r u r r r r u r o r www.nationalgrid.com/sof website: SOF 14 Voltage containment and regulation requirement (Slow Progression 2016/17) containment and regulation requirement Voltage Figure 4.28 Results 4.30 Figure and 4.29 Figure 4.28, Figure describe the zonal maximum reactive power 2020/21 requirement by region in 2016/17, Progression Slow Consumer Power Consumer 2016 November Framework Operability System Chapter four Voltage containment andrecoveryrequirement(ConsumerPower2020/21) Figure 4.30 Voltage containmentandrecoveryrequirement(SlowProgression2020/21) Figure 4.29 Voltage management System OperabilityFrameworkNovember2016 o r r u r o r r u r r r a a ta e re at a ta e re at t a t a rth rth
t a t a th th a a a a e ate a a e ate e ate a a e ate tat tat tat tat a a a t a t a e a e rth rth a a a e a e a e a a a t a a a t a a t a a a t a t reater reater a a 138 Chapter four 139
the optimum balancing solution. balancing optimum the must be available in the steady state so that the to immediately respond to able are they impact may which state, post-disturbance Conclusions containment post-fault for requirements The as period the over increase recovery and synchronous from support available the generation declines. This is due the to ability of synchronous generators respond to a to voltage sustain and immediately disturbance and containment the throughout control recovery period. In specific regions, changes arise due changing to power flows and limited proximity of synchronous sources of reactive fast and dynamic immediate The power. synchronous from available responses dynamic by complemented be to need machines could responses Static sources. alternative be used between 500 ms and 30 s. Reactive the increase requirements absorption power most; in some however, particular areasthere is also an increase in reactive power generation required due specific to regional flows and requirements the cases, all In resources.
) )
Gvar
Gvar ). ) and17.8 ) and8.1 ). Consumer Power Consumer Consumer Power Consumer ) in comparison to 2016/17. ) in comparison 2016/17. to Gvar ( Gvar ( Slow Progression Slow Gone Green Gone ) in comparison to 2016/17. The ) in comparison 2016/17. to Consumer Power Consumer Consumer Power Consumer Gvar ( Gvar ( Slow Progression Slow Gone Green Gone Static reactive powerabsorption, assuming it can be switched between 500 ms and 30 s, is required increase to by 2025/26 by Gvar 11.3 ( ( requirement for static reactive power generation decreases 15.5 by and 14.6 and 12.3 The requirement for reactive power generation decreases 13.0 by The results illustrate an increasing requirement, requirement, increasing an illustrate results The dynamic fast and immediate the in particularly periods during timeframes absorption reactive support is generator synchronous when least available. In some areas, there is also is there areas, some In available. least immediate for requirement increased an or fast-acting reactive power generation, though the overall trend is a decrease. the by driven principally are Requirements sources synchronous large of displacement on the transmission system with those that do not provide an inherent overload capability for reactive support, or those which are where system distribution the in located system transmission the to contribution the is limited. There is therefore less resource address to acts naturally which available overload inherent an with requirement this response. capability immediate an and the system, transmission whole the Across analysis shows that that 2025/26 by across immediate for requirement the regions, the by increases absorption reactive dynamic Gvar23.4 ( ( 2016 November Framework Operability System Chapter four System OperabilityFrameworkNovember2016 140 Chapter five
141 141 142
Whole system coordination Whole system five Chapter Chapter 2016 November Framework Operability System 2016 November Framework Operability System Chapter five Insights 5.1 system coordination Whole System OperabilityFrameworkNovember2016 application ofnewcontrol approaches. system voltagecontrol through the potential todeliverenhancedtransmission Distributed energy resources havethe of flexibility. market accessforpotentialproviders it canincrease uncertaintyandrestrict constrained networks.Ifnotcoordinated, quick andeconomicconnectionto Active networkmanagementfacilitates timescales andinreal-time. balancing andoperability, inplanning operator. Thisincreases uncertaintyin output isnotvisibletothesystem An increasing amountofgeneration
enhance restoration options. flexible andnewtechnologiescould restoration. Providers needtobemore approachesconsider alternative tosystem develop theBlackStartstrategyand There isanongoingrequirement to generation growth. power flowscausedbydistributed effective inthefuture duetochanging disconnection isnotguaranteedtobe The functionoflowfrequency demand 142 Chapter five
143
.
resources a greater grow, level of whole to achieve this as distributed energy energy distributed as this achieve to system coordination is required. If this uncertainties additional achieved, be cannot will have be to factored into our requirements accountto for the behaviours of energy resources and networks which are not visible. Wholesystem coordination is a broad subject with many features which it is not possible fully to explore. have We therefore able are we which areas selective assessed demonstrateto are changing significantly according Energy Scenarios the to Future address operability requirements, when when requirements, operability address considered in the context of our balancing and flexibility work. It is therefore crucial new and resources energy distributed capabilities. service provider generation the of proportion increasing An mix is not bound the by same performance transmission-connected large as obligations plant. There is therefore also a need consider to codes industry of application appropriate the and frameworks ensure to that the system remains secure as the balance of energy neutral Our changes. location resource throughout continues solutions to approach this section; it however, is sometimes necessary distinguish to where current levels order In today. with consistent remain will that as we, an industry, respond this to system whole developing by challenge to access enable which approaches of visibility and coordination are assured by standards. and codes In our Balancing and Flexibility chapter, we have based our assessments on an assumption that the certainty of flexibility and reserve requirements ahead of time
Effective planning and operation relies on an behaviour and capabilities the of understanding of generation, demand and networks across be must Uncertainties system. whole the so phases planning in account into taken that resources can be coordinated efficiently and procurement of system services can be optimised. This topic considers a number of areas where better access enhanced to can system whole the across capabilities maximise our ability address to operability securely. and safely economically, needs Wholesystem coordination is not a new concept. we exchange Today data with distribution owners, network transmission service and generators owners, network operational and planning in providers timescales make to efficient decisions on 5.2 coordination? system whole What is behalf of energy consumers. This approach approach This consumers. energy of behalf structure historical the on based been has of predominance the industry and the of resources. energy centralised areWe now experiencing an energy revolution. small-scale and resources energy Distributed generators continue grow to across all of the system whole and scenarios energy future resource optimisation is required where suitable. longer no are approaches historical Previously, real-time data exchange has taken place directly between the system operator, network owners and large generators. There is now a role for a range of alternative approaches as aggregation and provision information to of location the and grow generators small energy resources in the network changes. voltage and frequency of assessments Our total the where time of periods highlight transmission the on available resources system are not sufficientto economically 2016 November Framework Operability System Chapter five generation Voltage control from distributed area. licence West South the in experience their from (WPD) Distribution Power Western from by insight supported behaviours, variability of network and distributed generation transmission system operator with services the of interactions complex increasingly the Active network management needs. in service uncertainty reduce and interactions cross-system to understand operator system the allows it as operation to efficient critical is resources of system coordination assessments. The visibility whole the of all influences which consideration andVisibility coordination Whole systemcoordinationtopicmap Table 5.1 Topic map 5.3 forward by UK Power Networks (UKPN) (UKPN) Networks Power by UK forward Innovation Competition proposal put Whole system coordination Whole System OperabilityFrameworkNovember2016 Black Start Disconnection Demand Low Frequency Resources Energy from Distributed Voltage Control Management Active Network Coordination and Visibility Assessment
explores a joint Network Network ajoint explores in place. place. in is strategy restoration system effective an that ensures which service Start Black the of status current the of assessment An grows. generation distributed as to operate ability the retain must An assessment of demand disconnection measures which Networks. Power UK control to the transmission system. Includes contributions from England, which have potential to provide voltage enhanced East South in resources energy distributed of assessment An Distribution. operator instructions. Includes contributions from Western Power distribution networks do not counteract transmission system managed actively that to ensure needed is which England, collaboration across the distribution network in South West An assessment of the active network communication and over-procured. not are services and met be can needs operability of and behaviour. performance certainty This ensures that An assessment of the visibility of generation requires additional Description is a fundamental explores
and need for new providers. new for need and strategy the of requirements the We explain failure. a system following restored be can system power the that ensures consumers This valuable insurance policy for energy strategy. Start Black the of requirements future Black Start requirements. future Electricity Networks Association to assess the through work of progress current and SOF of work the on update an provides as distributed generation grows. This section frequency demand disconnection devices low of operation correct the explores Low frequency demand disconnection voltage control to the transmission network. to provide East South the in resources energy distributed of use the to trial Grid National and explores the current status and and status current the explores
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DERs will have to supply an increasing an supply to have will DERs support services, system whole of proportion transmission low of periods during particularly system demand. The potential for widespread use of ANM inhibit to the ability for DERs to provide these serviceswhen they are required will mean that all parties must coordinate system, transmission the Unlike appropriately. distribution systems do not presently apply which performance standards same the this area may be necessary complement to needs. industry cross of assessments holistic demand frequency low Regarding industry work current (LFDD), disconnection is in its early stages of analysis. Initial results suggest that given the variability ofoutput from that potential is there generation, distributed LFDD action in some areas may not act in accordance with expectations. This work has so far considered a limited range of conditions. Further work is required examine to broader low for options Future regions. and timeframes being are disconnection demand frequency group. industry working an by investigated assessment balancing our of outputs The traditional of availability reduced the illustrate providers of the Black Start service. There is an ongoing requirement develop to the Black Start strategy and consider alternative approaches system to restoration. Providers of Black Start need be to more flexible in the providers technology alternative and future are required enhance to restoration options. ANM facilitates early access and low cost energy distributed for solutions connection resources (DERs) in placeof traditional network distributed of levels the Given reinforcements. assessment, balancing our in generation require resources respond to broader to system needs. Parallel developments in
,
GW of generationGW output is Slow Progression In Slow GW. MW is necessary, direct by or GW isGW not visible. The Requirements for Generators code, code, Generators for Requirements The which will lead increased to costs and the required. being measures emergency of risk Presently, up 17 to this By 2025/26, number is up in 2016/17. twiceto as high in Power the Consumer scenario, at 34 up 27 to implementation codes European part of as impact considerable a have could GB, in The visibility. generation of levels overall on analysis supports the case that reducing the would apply requirements which at threshold greatly improve visibility of small generators and improve their ability support to the whole developments, code to addition In system. alternative methods improve to visibility are required. Appropriate aggregation distributed of managing to contribute also could resources of levels ensure To requirements. regional today, to equivalent visibility broadly remain installed an to down installations visibility of capacity of 1 indirect means, by 2025/26. There is an increasing range of distribution network regions that are likely implement to active network management (ANM) systems over the next five years. Given the range of areas between possible interactions of function, ANM and operability system whole such systems need be to designed and greater with appropriately coordinated companies network between collaboration and the system operator. not visible during the lowest visibility periods Our assessment of Visibility and Coordination Coordination and Visibility of assessment Our illustrates the consequences of the growth in operator. system the to generation distributed Most of these generators are not required control, and metering operational provide to therefore the system operator’s visibility of the decrease will real-time in output generation total remarkablyin future years. Unless actions to increase will this taken, visibility are improve uncertainty operability in requirements, 5.4 Consequences and requirements 2016 November Framework Operability System Chapter five the term transmission system operator (TSO operator system transmission term the operator, system transmission the to provide have not do resources energy distributed most years. Depending on their installed capacity, ten next the over resources energy distributed of capacity installed the in increase an is there scenarios, energy future the of all Across Background requirements. operability in whole system uncertainty grows. increases This generation visible to the system small-scale as operator output isnot of total generation proportion increasing An coordination and Visibility 5.5.1 Assessments 5.5 system coordination Whole 4 3 2 1 System OperabilityFrameworkNovember2016 operational time horizons. a method of instruction through planning and and aggregator), an as (such party athird via or mechanism for data provision, whether direct characteristics and behaviour. This requires a their of understanding an with real-time, in generators of output the to see TSO the for ability an as visibility defined have we section, this In the magnitude of requirements. operability to adds uncertainty This reduces. resources metering, the TSO’s visibility of available generators, which have to provide operational these generators displace the large centralised TSO. As to the invisible effectively are they that with real-time operational metering, meaning it from the operation of distribution networks. is used throughout this chapter to distinguish GC0042: http://www2.nationalgrid.com/UK/Industry-information/Electricity-codes/Grid-code/Modifications/GC0042/ Distribution Code: http://www.dcode.org.uk/the-distribution-code Grid Code: http://www2.nationalgrid.com/UK/Industry-information/Electricity-codes/Grid-Code of operation the from it todistinguish chapter this distribution networks. throughout used is (TSO) operator system transmission term The 1 ) Under Grid Code modification GC0042 modification Code Grid Under TSO. to the supplied estimates generation growth in the annual planning distributed for accounted have DNOs and limited requirements for information provision with resources these to manage possible been portion of total generation. It has therefore aminority up made historically have They Hydro Electric Transmission (SHETL) area. 10 than less and area (SPT) 30 50 than less being as defined are generators small planners and operators with the capacities of provide units larger these for requirements large connections under the Grid Code. The and by medium provided information of levels to the comparable however, not, directly is TSO. This to the information, protection and network with together 1MW, than greater and capacities for installations with a capacity provide information about generation types Under the Grid Code Grid the Under MW in the Scottish Power Transmission Transmission Power Scottish the in MW MW in England and Wales, less than than less Wales, and England in MW 2 and Distribution Code MW in the Scottish Scottish the in MW
4 , DNOs 146 3 , Chapter five 147
(CP), (NP) (NP) future (SP). r re r re C er er e ree e (GG), Progression No MW and micro generation which is which generation micro and MW MW according the to 2016
Slow Progression Slow r e erat r Consumer Power Consumer scenarios: energy Green Gone below 1 metering, are then set for each band. Greater requirements, capabilities and certainty system in which could be derived from more accurate resources, energy distributed about information operated be to system whole the allow could more efficiently. The levels of each band are consultation. under presently a providing is generation Distributed overall the to contribution greater progressively system, whole the of requirement generation not just at times of minimum transmission system demand, but across the whole year. illustratesFigure 5.1 the breakdown of installed is which generation distributed of capacity 1 above and
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6 ) code within 7 shows that the C er er r re r re e ree e 5
tr te e erat tr te EGrid Code modification GC0048: http://www2.nationalgrid.com/UK/Industry-information/Electricity-codes/Grid-code/ GC0048: modification Code EGrid Modifications/GC0048/ https://www.entsoe.eu/major-projects/network-code-development/requirements- (RfG): Generators for Requirements for-generators/ ENA High Volts Working Group: Technical Feasibility Report: http://www.energynetworks.org/assets/files/news/publications/ Report: Feasibility Technical Group: Working Volts High ENA Reports/ENAHVWGReportFinal.pdf which is in the process of implementing the (RfG Generators for Requirements real-time behaviour of these units can deviate deviate can units these of behaviour real-time notably from expectation. The industry currently has a joint Grid Code and (GC0048 group working Code Distribution 6 7 5 Figure 5.1 FES 2016 breakdown of distributed and micro generation installed capacity FES 2016 breakdown of distributed and micro generation ahead of real-time, performance real-time, of ahead generation operational anticipated and characteristics patterns. Given the ranges of type and size of distributed resources, the capabilities that exist are presently self-certified, contraryto those for larger generators which are certified theby system operator. Self-certification is lessreliable than certificationby the TSO. report by Association Networks Electricity An the High Volts Working Group 2016 November Framework Operability System GB. Under RfG, generators are assigned a banding according size. to Requirements, for example on data exchange and operational Chapter five Visibility ofsolarPVcapacityinstalledbehindaconverter Figure 5.2 with differing generation capacities behind the but capacity export same the with installations solar two of behaviour the demonstrates 5.2 Figure equally. rating converter the and panels the to size economic be not may it where capacity which is behind the connection, solar generation behaviour is the level of A particular challenge in the prediction of voltage regulation requirements. the of sensitivity and shape the on influence PV output will have an increasingly greater Management chapter, we described how solar for wind and solar generation. In the Voltage impact of and importance accurate forecasts the demonstrates year this August from The Balancing case and study Operability system coordination Whole System OperabilityFrameworkNovember2016 Five 1 MW panel arrays =5 MW arrays 1 panel Five MW Three 1
MW panel arrays =3 arrays panel MW
MW Energy storage device 3 MW rated at Converter 3 MW rated at Converter
3 MW 3 MW its operation, as is also illustrated in Figure 5.2. Figure in illustrated also is as operation, its influence or to monitor ability an and convertor information regarding design behind the touncertainty system operation without developer, such projects represent additional the to efficient potentially While installation. panel solar to apure compared shape load in differences have These projects. PV solar increased growth of combined storage and in to result likely is energy solar excess waste than rather to accumulate by storage pumped storage. provided The opportunity 0.4 from ranges devices storage energy of capacity installed the network connection. According to FES W ( 2.8 GW Gone Green GW ( Sunny day Potential for energy storage Typical day Potential to export stored energy rating Converter Typical day Sunny day rating Converter No Progression ) by 2025, excluding ) by 2025, excluding ) to to ) 2016, 2016,
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and . The fact that scenarios. Consumer Power inGW Consumer Slow Progression Slow Slow Progression Slow GW. By 2025/26, there By 2025/26, areGW. periods where generation output which is not visible to the the to visible not is which output generation system operator according this to definition. generation of distribution the show results The for sources invisible and visible from output and in Power the 2025/26 Consumer 2016/17 and The results clearly illustrate the increased increased the illustrate clearly results The impact of distributed resourceswhich are not visible over time. Of particular note is the elongated tail theto right-hand side of the impact increased the indicates This distribution. of weather events when solar PV or wind generators renewable distributed from output the highest total outputare high. In 2016/17, from generators which are not visible is 17 twice to up is output invisible unconstrained as high, 34 GW 27 in the trend is consistent across scenarios demonstrates the importance of action to the in operability system whole the secure context of increased impact of weather-driven future. the in behaviours
MW within MW in the SPT area MW in the SHETL area). Figure and 5.3 Currently, a project of the same size connecting under different codes in different regions of output power different produce will system the performance. difference The and behaviour in the codes is reflective of historically limited telemetry monitorto and manage distributed in outlined As scale. this of generation Voltage and Management Frequency the relation in behaviour chapters, Management a disturbanceto is important, particularly steady drive needs post-disturbance when or planning no Currently requirements. state behaviour the about information operational of small-scale generators during a frequency frequency a during generators small-scale of or voltage disturbance is made available to the TSO and very limited information is owners. network distribution to provided Results In our assessments, visibility is definedby the current Grid Code and Distribution Code which above generators, small for thresholds visibility the to TSO is required (50 England and Wales, 30 and 10 Figure illustrate 5.4 the proportion of the total 2016 November Framework Operability System Chapter five Whole system coordination Whole Generation outputnotvisible(SlowProgression) Figure 5.3 System OperabilityFrameworkNovember2016 u r of r r Generation outputnotvisible(ConsumerPower) Figure 5.4 u r of r r
r o ou u r o o r o ou u r o o 150 Chapter five
151 a small number of periods in 2025/26 where where 2025/26 in periods of number small a over 90% of total generator output is not visible theto system operator. In 2025/26, theIn 2025/26, movement the to right-hand side of the plot shows that there are an visibility where periods of number increasing constraint visibility, improved Without lower. is are there instructions, emergency or actions
in the form ro or o of o r o ou u o o r o ou u o ro or o of
Figure 5.5 ) visible with current thresholds (Consumer Power Generation output not Figure expresses 5.5 generation output Power Consumer visibility for of a distribution curve. The shapeof the spent time of proportion the shows curve at varying levels of generator output visibility and 2020/21 2025/26. in 2016/17, 2016 November Framework Operability System Chapter five Whole system coordination Whole arrangements in place for visibility of generators generators of visibility for place in arrangements to a1 down 2025/26, mechanisms for visibility of generation to 2016/17 visibility of in level equivalent an to achieve order in that 5.6 shows Figure System OperabilityFrameworkNovember2016 Generation outputnotvisiblewith1 Figure 5.6
MW level is required. Even with with Even required. is level MW ro or o of o r o ou u o o ou u r o o of ro or o
MW threshold(ConsumerPower) 061. 2016/17. n i periods onerous most the than worse is proportion of the year where overall visibility to a1 down MW level, there is still a large alarge still is there level, MW
152 Chapter five 153
Beyond increasing visibility, which will reduce the reduce will which visibility, increasing Beyond also is there operation, real-time uncertainty of distributed coordinate to requirement growing a energy resources support to the system in other areas such as frequency and voltage historically support This has management. been provided minimum by performance regards With generators. centralised for criteria aggregation,to it is important that the net performance of aggregated resources are instructions that and predictable, and understood do not cause localised operability issues. visibility, reducing address to action Without there will be an increased risk in the future that emergency instructions will have be to used. These arrangements involve the TSO distributed disconnect to DNOs the instructing generation in order regain to acceptable use frequent The performance. network of such measures is unlikely be to desirable economic. or
MW Conclusions Distributed energy resources, definition, by are connected within distribution networks networks distribution within connected are and are not usually requiredhave to the capabilities support to the system in the same fewer When do. generators centralised that way centralised generators are running, there is the potential for a gap in capabilities develop. to It will be necessary for distributed resources to provide the system support that has historically generators. centralised the by provided been responsibility, of transfer this facilitate To it will also be necessary ensure to that the it. accommodate can networks distribution Throughout the next decade, it is only possible retainto an equivalent level of visibility today to for most of the year ensuring by that all energy resources with an installed capacity of 1 or greater are visible the to whether TSO, could This means. indirect through or directly modifications, code through achieved be RfG with of implementation the including use the through or levels, banding appropriate of aggregation. The latter involves a role for third parties collate to numerous small resources and present the aggregate information the to TSO. 2016 November Framework Operability System Chapter five generation growth in the past, the dramatic incremental accommodate to sufficient been have may approach this While permitted. been have not would it reinforcement, a breach of limits without conventional Historically, if the connection were to trigger apply. also may limitation current or a thermal voltage; however, other constraints such as with associated to be tend scenarios these in constraints common most The scenario. flow its unconstrained output during a credible peak distributed generation connection is based on Traditionally, the assessment of a new conventional network reinforcement. with associated delay and cost the to avoid helps often It possible. as effectively cost facilitate new connections as quickly and and capacity network existing to maximise DNOs the helps which approach an is ANM for more widespread application. considerations identify and area this in WPD of experience the on based (ANM) management network active WPD, explore we with 1.2 approximately which of connected, generation 2 about now is there area, licence West South (WPD) Distribution Power Western the In time. the of all unconstrained forget’ methods of control where output is and ‘fit conventional using available capacity network the exhausting is networks distribution The increasing connection of generation within Background the whole system. across is required coordination operational planning and Enhanced services. to the system access balance and ability system operator’s the transmission affect could adversely schemes of use active management Increasing network Active management network 5.5.2 system coordination Whole System OperabilityFrameworkNovember2016
GW is solar PV. Conducted in collaboration GW of distributed GW distributed of and demand. by accounting for variation in generation utilisation network maximising of concept same the from derived all are They below. outlined are approaches these of Anumber applied. of different connection approaches have been anumber area, licence West South WPD the In method. complex most the also but able most the is management network Among these alternative approaches, active assets. network existing the of use efficient make and capacity this to maximise by DNOs connection approaches have been introduced alternative of A number time. the of rest the additional capacity available in the network is there means ayear, which times a few half-hour period. In reality, this may only occur studied. This is the typically most challenging and identified is scenario flow apeak in connection, the impact on the network For conventional distributed generation addressed. be must services and instructions TSO with interactions of however, anumber to facilitate distributed generation connections; to play role important an has therefore ANM at times when the network is constrained. output their to curtail agree they provided generators to connect in these regions, or transmission network. ANM allows new close to constraint limits on either the distribution operating now are regions many and available capacity the of much up used rapidly has increase in distributed generation connections
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8 Active network management network Active Figure illustrates 5.7 an example of a network where a number of the generators are subject activeto network management. It should be noted that other distributed generators in the network are contracted with the TSO provide to reserve operating short-term services as such (STOR) or demand-side response (DSR). Existing generators not subject ANM to are resolveto the constraint. In the example in would generators wind and solar the 5.7, Figure instructions. curtailment automatic issued be If a measurement is not provided when prompted, the server will take a ‘fail safe’ not illustrated. not the of state the monitors scheme ANM The an and points constraint critical at network ANM server runs a power flow management breach values measured the When algorithm. a constraint threshold value for a defined required the server calculate the will period, generators managed of output in reduction action ensure to the constraints are secured.
MVA inMVA kV connected generators under 1
ENA Active Network Management Good Practice Guide: http://www.energynetworks.org/assets/files/news/publications/1500205_ENA_ANM_report_AW_online.pdf 8 Soft intertripSoft Soft intertrip is a simpleimplementation of clusters small for designed is which ANM constraint. single a behind generation of Centralised control uses a live voltage or limit constraint assess the to reading current and ramps down the output of generators if it is breached. This is a low cost option for areas where full ANM has not been rolled out. connectionTimed option an as designed were connections Timed for 11 generation. solar by dominated are which areas It allows the generator export to during winter and at night when there is low or no output during curtails but generation, solar from summer day time. The main advantage is that it does not rely on a control system since a timed agreement. commercial a purely is connection This keeps costs low and timescales short for generators. small connecting Export limitation Export limitations allow a customer install to more generation than the connection export capacity, subject specific to criteria regarding how much can be installed and how the limit is controlled. Typically there are two types of customers that find these connections useful: an existing generator who wants increase to their installed capacity or a demand customer their above generation install to wants who existing export capacity. 2016 November Framework Operability System Chapter five restrictions to ANM controlled connections. rapid to implement necessary be would it ANM signal. Should the system be unavailable, required to respond automatically to the also are Customers customers. affected communication channels between it and and server the of availability the on rely which impact the constraint. ANM does optimised LIFO stack to only generators curtail an to apply ability the has also It constraints. multiple and generators more for but do, can intertrip asoft that everything do can ANM new connections. by affected not are and rights access their maintain generators existing that ensures it becomes economically unviable; however, generators from connecting when curtailment limit does It clear. and simple agreements is generally used as it keeps commercial dates when connection contracts were signed, the on based is which arrangement, (LIFO) off first in last the areas WPD In implemented. commercial arrangements that could be of arange are There generators. different which determine the assigned priority to access, of principles on based is Curtailment Illustrative activenetworkmanagementexample Figure 5.7 system coordination Whole System OperabilityFrameworkNovember2016 network Transmission 400
kV
132
constraint kV Thermal network Distribution 33 Solar Generation
kV constraint 1 ANM server Voltage CHP Generation
Wind Generation TSO access to services procured from DERs. DERs. from procured to services access TSO on impact an have can which flexibility, and capacity of to certainty access of trade-off approaches must be weighed against the The impact of alternative connection investments and operational cost savings. to network regard with needs network efficientlyoptimise transmissionand distribution to arequirement is There system. whole the across impact holistic the to understand conventional approaches, it is necessary from away move we As consumers. of benefit optimised operational solutions to the overall telemetry of networks which can deliver possible through improved control and made are discussed approaches the of All reinforcement. a network for opt than rather forward to go not choose usually developments proposed significant, be would other. In regions where the imposed restrictions likely if ANM limitations are layered upon each longer periods. This becomes increasingly for active becomes constraint the if time over generators becoming economically less viable to lead also could ANM server. ANM by the out carried logic processing the to update a need network change substantially, this could trigger the on flows underlying the as time, Over Demand 33 kV 33 Wind Generation 11 kV 11 constraint 2 Voltage 11 kV 11 415 V 415
156 Chapter five 157
r re r re Without coordination of activities between between activities of coordination Without capacity was assumed to be in proportion to to proportion in be to assumed was capacity the maximum winter demand based on P2/6 2016/17 for results The standards. planning versus are shown 2020/21 in Figure 5.8. This gives a view of the regions where it is most likely that existing network capacity will be used up and ANM may therefore be necessary in lieu of network reinforcement. the TSO and DNOs, there is potential for ANM balancing TSO’s the counteract to schemes actions or sterilise to the effect of system services procured from DERs. This could lead increasedto costs the to consumer and risk securityto of supply if services cannot be required. when delivered
C er er
e ree e
t e e t re re e e t re re th t et r e t e t Impacts on system operation system on Impacts As National TSO, Grid operates the GB supply balances and network transmission with demand in real-time. The DNOs have securing for responsible been historically their networks meet to the required standards demand. and supply balancing in role no with schemes ANM of application the Through have DNOs connections, alternative other and an increasing impact on the power flows within their networks. Regions where ANM is likely to be required by 2020/21 Regions where ANM is Figure 5.8 Results of likelihood the investigates assessment The resolve to implemented being schemes ANM networks distribution the within constraints in future years. It was based on the installed capacity of distributed generation in an area compared the to network capacity of the distribution system in those areas. The network 2016 November Framework Operability System Chapter five Interaction betweenANMandShortTerm OperatingReserve(STOR Figure 5.9 generator unavailability. unplanned of case the in or forecast the than greater being demand real-time of case the in power to reserve access fast with TSO the provides that service important an is STOR zero. be therefore will TSO to the effect net The exceeded. being from limit constraint generation will be to curtailed prevent the other and server ANM by the detected be will isservice called, the increase in generation is located within an ANM scheme, when the provider the If services. reserve or response interaction equally applies to other frequency this (STOR), however reserve operating term short of example the used have we diagram, the In service. areserve with scheme ANM an of interaction the 5.9 shows Figure system coordination Whole 9 System OperabilityFrameworkNovember2016 term-operating-reserve/ TermShort Operating (STOR): Reserve http://www2.nationalgrid.com/uk/services/balancing-services/reserve-services/short-
DEMAND FREQUENCY
50 Hz 50
the network if the conflict cannot be resolved. be cannot conflict the if network the of part unconstrained to an to connect obliged be should they whether and zone ANM existing to an connection for apply who providers new regarding questions raises also It needed. be would TSO and DNO between agreement effectiveness of ANM schemes so mutual the reduce would however, this providers, STOR for reserved be could constraint each autonomous. A portion of the capacity behind mostly are actions network active as challenging presently is ANM and services frequency between conflict the Resolving GENERATION 9 )
158 Chapter five 159 GENERATION The demandincrease instructed the by service could be counteracted the by generation increase instructed a DNO by ANM scheme in an export-constrained distribution network, Ifas a Demand shown in Figure Turn 5.10. Up service provider was located within an export-constrained network with ANM, the see would consumption power local in increase the release and generation for capacity greater This generation. the to capacity commensurate would negate the Demand Up instruction. Turn 50 Hz FREQUENCY
DEMAND MW was in use from May
Figure 5.10 Interaction between ANM and Demand Turn Up Interaction between ANM and Demand Turn Demand Up isTSO a Turn service to increase to consumers power larger encourage reduce to generators distributed or demand, generation, when there is excess energy on the system. It is typically applied overnight and weekend afternoons. the Demand In 2016, Turn Up service of 309 to September within two operating windows: windows: operating two within September to service window day and window overnight afternoon). holiday bank and (weekends The day service window was selected to coincide with periods of low demand and maximum output from solar generation. This also happens be to the time when ANM schemes are most likely be to operating. 2016 November Framework Operability System Chapter five maximise the use of existing network assets. assets. network existing of use the maximise application of dynamic line ratings to further the and levels fault managing as such areas additional in services to provide ANM for timescales could unlock the additional potential networks throughout planning and operational areservices available. Information across which of visibility with system the secure can rooms control the that so to real-time continue to needs This compromised. not is delivery service that to ensure developed be will ANM information is essential to understand where of flow atwo-way timescales, planning In collaboration between DNOs and the TSO. greater for aneed is there operation, economic and stable continued to ensure order In awhole. as system the for effects to detrimental lead could this coordination, infrastructure; however, without appropriate network distribution the of use efficient more reinforcements. ANM schemes allow for faster connections by avoiding large network and cheaper offer DNOs to help designed mostly are ANM of applications current The Future development of ANM TSO. the and DNOs between coordination the ANM scheme instructions and improved forecasts through better understanding of demand system transmission the in uncertainty the to reduce required is Action behaviours. expected from diverge could behaviour its as forecasting demand overall the of accuracy the impacts further ANM of use The predictable. less networks distribution with exchanges system demand forecasts, making power increase the in uncertainty the transmission Increasing levels of distributed generation suppressing the transmission system demand. by TSO, manifests to the visible not generally is power output of distributed generation, which current and historical weather conditions. The historical demand data, weather forecasts and of analysis the involves This change. demand forecasting to predict the minute-by-minute demand to real-time close conducts TSO the demand, and generation to balance order In system coordination Whole System OperabilityFrameworkNovember2016 ongoing implementation. appropriate coordination, is to important control actions and ANM operation, with TSO of visibility Enhanced consumers. for operation system of cost the and risks security TSO actions, which would increase system in additional needs or capability countermand system as a consequence. This could result adversely affect TSO operations and the whole could roll-out ANM unmanaged, If approach. current the with associated complexities and limitations benefits, the highlighted We have across distribution networks in the long term. implemented widely be will it that expected generation to constrained networks and it is distributed connecting of way effective an to be demonstrated been has ANM limits. distribution networks are close to network reinforcement as regional transmission and potential to trigger various needs for network the has This decade. next the throughout within the distribution networks continues connected resources energy of growth The Conclusions Networks in the South East. working in collaboration with UK Power Resources, where National Grid has been topic, Voltage Control from Distributed Energy following the in explored is example An level. network atransmission at principles ANM of carried out to investigate the implementation being are studies and projects of A number
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kV
kV distribution network. The GSPs GSPs The network. distribution kV
The proposal focuses on electricity networks networks electricity on focuses proposal The distribution The England. of East South the in network in this region is owned and operated UKPN,by connected the to transmission (GSPs). points supply grid four via system 400 the where substations the are These Ninfield, Sellindge and Canterbury North, 5.11. Figure in indicated 132 considered in the project are: Bolney, transmission network interfaces with the the with interfaces network transmission summarises the results from the initial initial the from results the summarises SOF Background National Grid and UK Power Networks (UKPN) are working in partnership investigate to an energy distributed using to approach innovative control enhanced voltage provide to resources Transmission The system. transmission the to and Distribution Interface (TDI 2.0 project 2.0) seeks demonstrate to a coordinated whole system approach which leads more to efficient project The operation. and planning network implementation the investigate to proposes of a novel voltage control arrangement which presents an effective alternative to of section This reinforcement. conventional the Distributed energy resources additional deliver could capacity through control approach, a coordinated voltage 5.5.3 energy from control distributed resourcesVoltage as proposed by National Grid and UK Power Networksas National proposed Grid by and UK Power through 2.0 TDI the project. 2016 November Framework Operability System assessment phase of the project, based on based project, the of phase assessment study work conducted Moeller by & Poeller Grid. National of behalf on Engineering Chapter five Whitson Bridgwater The TDI2.0region Figure 5.11 system coordination Whole System OperabilityFrameworkNovember2016 Seabank Chickerel Ardmor Harris l e Stornoway Dunvegan Iro Broadfor nA d
cton Carradale Mannington Indian Queens Pembroke Port Deani Nant Inveraray T Quoich aynuilt Ann Crossai Melksham Grudie Bridge Cruachan Dunoon e Caennacroc Culligran Whistlefield Clachan Fort William Auchencrosh Hunterston g Corriemoillie Aigas Saltcoat Spango Dalmally Va Meadowhead lley Luichart Arecleoch s Glenluce Kinlochleven Kilmorack Maybol Stewar Newton Minet Strathleve Fasnakyl Markhill Devo Kilwinning Mossford Moor Sloy Cassley Morrison Glen Ay Swansea North Invergarry Wy Inverarnan e Landulph Neilston l Erskine Beaul r Cashlie Kilmarnoc t To Helensburgh n lfa Baglan Bay wn Rannoch Alverdiscott For e Orrin Tu Killin Glenlee y Kilmarnock Whitelee Extn tA Coylto Sout mmel Bridge Glendoe k Busby T Lochay TRANSMISSION SCOTTISH HYDRO-ELECTRI Windyhill y Whitele New Cumnock ugustus ongland Foyers Shin Pentir Marchwood Dingwall h Langage Ffestinio Inverness n Lambhill e Dinorwig Margam Strathaven Kendoon Carsfa Finlarig Earlstoun Errocht Errocht Bonnybridge Lairg Sout Kilbride Eas Clydes Mill Tr t Coalbur h St. Fillans Denny Knocknagael Pyle awsfynydd g Alness d Stirlin Easterhous Wishaw Elvanfoot y y Coatbridge Bodelwyddan Tu g Newarthill Dounreay mme n Devonsid Errochty PowerStatio Aberthaw Abham Upper Boat Dumfrie Coalbur e Nairn l Alpha Steel Longannet Mo Black Law Garten Boat of Brora Dunbeat Kincardine e Grangemout Bathgate Nurslin ff SP Livingston Fawle Broxbur at s n Hinkley Point Clyde (North Exeter Cluni C Rassau Dunfermline TRANSMISSION Clyde (South) Ecclefechan h Cardif n Deeside East Te Burghmui Chapelcross Cilfynydd e Harestanes Gorgie lford Rd Capenhurst Currie Charleston Inverkeithin h Thurso Mybster ) Uskmout f T Blackhillock Tr Elgi n Mossmorran Glenrothes aunton W Axminster . Shrubhill Kaimes emorfa Whitehouse Glenniston estfield Imperial Dunlaw Extensio Connah’s Quay n r Park Gretna y Smeaton Portobelll Kirkby g g T Stanah Glenagnes ealin h Redhouse Legacy LT Rocksavage Cupar L Cockenzi Whitson Leven yndhurst D Rainhill o g Bridgwater Harker Shrewsbur n Heysham W Farm Seabank Bramle Dudhope Ta ashway Crystal Ri Keith Dudhope Penwortham Chickerel e Hawick Middleton Fallago rland Frodsham Galashiel Kintor Botley W Quernmore Carrington South Manchester Dunbar Milton of Craigie Kearsley g Hutto Ironbridge y Bishops Wood e Fiddlers Ferry l Didcot s n Arbroat Iro Craigiebuckler Padiham Wa Penn W Rochdal nA Macduf Eccles To Strichen Ocker Hill oodhill lham y Berwick rness Culham cton h Daines Rugeley Fiddes Dyce Whitegate Mannington f Bredbury e Fourstones Melksham Macclesfield Stalybridge Bushbury Kitwell Persley ood Stella W Cellarhead Clayhills Willenhall Redmoss Willowdal Marshall Meadow Fraserburgh Lovedean Spennymoor Feckenham Minet Oldbur Stocksbridge Bradford W Winco Bank Shef Neepsend Nechells St. Fergus est est Elland Peterhead y Marchwood Jordanthorpe y e field City Bustlehol Norto Chesterfield Willington Te Berkswel Hams Hall Kirkstal Knaresborough mpleborough n Pitsmoor s Nursling Grangetown Fawle m Ferrybridge Coventry Blyth Drakelow l W Saltholme T W l Grange Skelto South Shields ynemout y est Boldon Of Fleet Stoke Bardolph ferton Hawthorne Pi Norton Lees W est W Melto Bramley Laleham n Hartmoor est East Claydon Aldwarke Botley W on Soar Ratcliffe T Thurcrof Hartlepool Staythorpe Enderby Brinsworth h Poppleton od Poin Didcot Fryston Monk Lackenby n Cowley Eggborough Culham Greystones Marnham High Thorpe ood Marsh Amersham Main Osbaldwic t Lovedean t t Iver Drax T eybridge eesside Patford Thornton Bridge W Fleet k est W Keadby Leighton Laleham Buzzard W Burto est Cotta Killingholme Iver Grendon eybridge n m Wa Nort Saltend Creyke Beck Ealin Ealin Willesden tford Sout Mill Hill Willesden Sundon Bank Humber Mill Hill Socon Eato h Chessington g St John’s h Wo Wy n od Bicker Fen Rye House Elstree Chessington Brimsdow Wimbledon Saltend Sout Spalding North mondley To Hedon Humber Refiner Grimsby W ttenham City Rd g St John’s Bolney Wo Cross Ne West Ham West w n Bridge Sutto Rowdown od Beddington Burwell Main h Redbridge Hurs est n Hackney Wimbledon Barking Cross Wa Pelham Wa West t y ltham To lpol Thurrock Littlebrook e East Northfleet Wa ttenham Braintre City Rd T rley Singlewel ilbur Bolney Ninfield Cross Ne y l e Kingsnort West Ham Rayleigh Main h w Grain Kemsley Rowdown Coryto Beddington North Canterbury Redbridge n Hurs Cleve Hill Dungeness Bramford Sellindge Barking West Norwich Main t Thurrock Littlebrook Sizewell East Northfleet Wa T rley Singlewel ilbur Ninfield y l Kingsnort h Grain Kemsley Coryto North Canterbury n Dungeness Cleve Hill Sellindge 162 Chapter five 163
be transmitted due to additional voltage voltage additional to due transmitted be system. distribution the support from The additional reactive power which power reactive additional The could be provided the to transmission system DERs. by could which power active additional The Network studies were conducted on a distribution and transmission of model joint studies The East. South the in networks typical conditions of range a represented regional and weather Different region. the in plant dispatch patterns were considered in a series of study cases. are in two specific areas: Due reactive to power requirements along the double-circuit route, the transfer of active power could be limited reactive by power needs. The studies consider low and high transmission the on constraints voltage network. The potential benefits assessed Low load base case. No DERs providing enhanced reactive power services. large and output medium at wind output, peak at PV solar with daytime Summer offline. plants synchronous large and output medium at wind output, peak at PV solar with daytime Summer online. plants synchronous Summer early morning low load with solar PV at zero output, wind at medium Summer early morning low load with solar PV at zero output, wind at medium output online. plants synchronous large and Description output and large synchronous plants offline.
5. 3. 4. Study Case Study 1. 2. There is one double-circuit transmission transmission double-circuit one is There other no with East South the along corridor routes for power transfer in the region. This is significant as new developments in the region on requirements additional place to likely are the transmission network. The proximity with mainland Europe means that a number of large which proposed are projects interconnector could lead both to heavier and more volatile flows. There is also substantial distributed region. this in growth generation The Voltage Management chapter identifies that additional reactive power will be required over the coming decade. The assessments for South East England specifically highlight and generation power reactive additional that assessment initial The needed. is absorption work for the project TDI 2.0 has investigated the could which benefits control voltage potential resources energy distributed by delivered be coordination through Grid National to (DERs) with UKPN. Table 5.2 Table Study cases 2016 November Framework Operability System Chapter five Voltage control methodology Table 5.3 system coordination Whole System OperabilityFrameworkNovember2016 output according to voltage fluctuations at at fluctuations to voltage according output power reactive their change can they meaning mode, control droop voltage in to operate able to be assumed been have resources these network, UKPN the in DERs from capabilities reactive maximum the to calculate order In Generation mixinthestudies Figure 5.12 system. transmission to the power reactive delivering at effective less much are DERs 33 at The studies included only DERs connected 3 2 1 Loop Control kV and above. Below this voltage level, level, voltage this Below above. and kV
than 30 Greater 2–20 5 1– (seconds) Timescale
transformer tapping Control the GSP response from DERs reactive fast Achieve Description transformer tapping Control the grid 36% 19% 45%
instructed to adjust the voltage target set-point. target voltage the to adjust instructed automatically be will DERs athreshold, crosses it If monitored. is GSPs participating at voltage The to voltage changes via voltage droop control. DERs on the network are programmed to respond Description maximise the DER voltage response. voltage DER the maximise to altered is target tapping The DERs. participating (132 transformers to grid Control scheme instructions are communicated as summarised in Table in 5.3. summarised as DERs, the from capability reactive potential maximum the to determine studies the into voltage control loops were programmed the point of connection. A number of novel connection criteria is shown in Figure 5.12. the met which DERs of mix generation The ar e erat e erat hr e erat kV/33 kV) containing containing kV)
164
Chapter five 165
indicate reactive power absorption. loop 2 and control loop 3 have activated. Management Voltage the with Consistent values negative and generation power loop 1. Theloop final 1. response is after control reactive indicate values positive chapter, is the reactive power provided after control across all four GSPs. The initial response response initial The GSPs. four all across control needs. The results were recorded as snapshots of reactive power provision u u u u
a re p e a a re p e a
t a re p e t a t a re p e t a
o r r o r o r r o r Figure 5.14 High voltage response Figure 5.13 Low voltage response Results Phase 1 – reactive power response from DERs from For the first phase of assessment, both low and high voltage excursions were simulated in much how assess to network transmission the reactive power could beachieved from DERs. Projects due connect to the to transmission network were included reflect to future voltage 2016 November Framework Operability System Chapter five in the region. developments network other for account not which has a lower voltage post-tap. This does 117 0.945pu. This corresponds to an additional to approximately elevated is voltage loop, control final the of implementation the Following Ninfield andBolneypower-voltage curves Figure 5.15 voltage condition was when solar PV and tapping had taken place. The most challenging transformer after and contingency the after both voltage system astable required study condition, which is a double-circuit fault. The occur under the most onerous contingency to likely is this as studied was case voltage For the second phase of assessment the low network capacity Phase 2 – additional transmission system coordination Whole o r u System OperabilityFrameworkNovember2016 a e a e MW of active power capacity at Bolney, Bolney, at capacity power active of MW Ninfield e
C tr p e Ninfield C tr p e Ninfield o r o r
fast timescales (1-5 seconds). in provided be can respectively Mvar 98 and Mvar 86 figures, these Of tapping. transformer power absorption could be provided following reactive of Mvar 226 and generation power to 121 up GSPs, reactive of four Mvar all across generation and distributed synchronous plant 905 considering when that determined has project The system. the of 5.15Figure response the shows the lowest value (0.88pu) at this location. busbar in the study region as voltages reach critical the is Ninfield that show results The synchronous generation is not available. post-fault, when voltage from support large occur requirements power reactive greatest the because expectations with consistent synchronous plant output is low. This is wind generation output are high and large Additional capacity (0.945pu)
MW of solar PV, wind
166 Chapter five 167
10 The initial TDI 2.0 assessment work has work assessment 2.0 TDI initial The demonstrated that it is possible provide to voltage system transmission enhanced energy distributed utilising by performance resources with a novel control approach. Further details of the project can be found Competition Innovation Network the in the on available pro-forma, submission Ofgem website. Ofgem
MW could be connected in the whole the in connected be could MW
TDI 2.0 project proposal: https://www.ofgem.gov.uk/system/files/docs/2016/04/electricity_isp_proforma_nic_12_04_2016_final.pdf proposal: project 2.0 TDI 10 response capability, up to an additional additional an to up capability, response Conclusions 2.0 TDI the for assessments initial The project are proof of concept rather than however, studies, planning operational a number of conclusions can be drawn regarding the potential benefits deliveredby numbers response the While approach. this may appear low compared the to capacity of generation this of much study, the in generation is heavily distributed at great electrical distance theto four GSPs considered. It may be possible develop to a sensitivity index to most be would generators which determine effective in the delivery of Mvar support at level. transmission a reactive above the considering When 186 study region. The results indicate that plant in the Bolney and Ninfield region would be the most beneficial for provision of voltage circuit double critical the support under case. contingency 2016 November Framework Operability System Chapter five (Demand Control) 6 Code Operating under Code Grid the Disconnection (LFDD) and is described in approach is called Low Frequency Demand recovery actions. This layered defence system for need the avoid and network a core system until is equilibrium reached to maintain quickly reduce the load on the transmission 48.8 disconnect demand if frequency falls below to maintain relays which will incrementally required therefore are networks Distribution procured. been has the quantity for which frequency response than greater generation of loss atotal cause or coincident independentevents, which could faults cascade include events These them. for response frequency to procure economic or reasonable be not would it that enough unlikely to be considered are these of outside Events the unplanned disconnection of generation. elementscertain of network infrastructure or of loss the includes It Standards. Supply of Quality and Security the in specified are which events, of anumber for system power the Frequency response is procured to secure it. to recover order in required is disconnection demand and range operational normal the of situation, when frequency falls below the limit emergency an in happens what explores Frequency Management chapter. This section normal operation are considered within the Requirements for controlling frequency under Background to in the future. effective be is not guaranteed ofthat the disconnection function low demand frequency powerChanging flows mean networks in distribution Low disconnection demand frequency 5.5.4 system coordination Whole 12 12 11 System OperabilityFrameworkNovember2016 Grid Code: http://www2.nationalgrid.com/UK/Industry-information/Electricity-codes/Grid-code/The-Grid-code/ 91725ECF799B/32165/PublicFrequencyDeviationReport.pdf Public Frequency Deviation Report: http://www.nationalgrid.com/NR/rdonlyres/E19B4740-C056-4795-A567- Hz down to 47.8 down Hz 11 . Hz. The intention is to to is intention The Hz.
48.795 was nadir frequency the and disconnected was 546 Approximately LFDD. of 48.8 below fell Frequency procured. been had response generation loss (1260 single largest the of size the than 58% larger was This minutes. ahalf and three of period of generation being disconnected over a 1993 in resulted generation distributed of four large generation units and a collection of loss coincident The 27 2008. May was operation to LFDD due disconnected were customers of number asignificant time last The generation. distributed in growth by the undermined but its present implementation could be emergency, an of event the in controlled to be frequency allows LFDD of operation Effective stages of LFDD were not required not were LFDD of stages remaining The minutes. seven approximately online, frequency gradually recovered over Hz. As reserve services were brought brought were services reserve As Hz. Hz which triggered the first stage stage first the triggered which Hz
MW), for which frequency MW of demand demand of MW 12
. MW MW
168 Chapter five
169
The first task for the workgroup wasto determine how well the schemes would currently work and how much demand would the of effectiveness The disconnected. be LFDD schemes under a range of different DNOs assessed. was conditions weather provided metered data show to how much per disconnected been have would demand LFDD demand block at three different times of year. summer considered far so has workgroup The conditions sunny demand conditions, minimum and windy conditions across the year in England and Wales. In some areas, the data disconnect would relays LFDD that showed more generation than demand. The Grid Code specifies that if frequency 60% of demandshould should fall 47.8Hz, to temperature on based disconnected be corrected winter peak demand. The same principle was applied the to three days shows 5.16 Figure assessed. were which the percentage of demand which would have been disconnected on each of these days. 2015. To explore this issue further, an ENA workgroup was set up so that the system operator could work with the DNOs understand to the changes assess and functionality scheme’s required. be may which are blocks disconnection demand Currently, winter temperature-corrected to according set peak demand levels, as specified in the Grid there changes, landscape energy the As Code. is a need assess to LFDD operation at all times generation distributed when particularly year, of output is likely be to high. Discussion With growth in distributed generation at are relays LFDD which below levels voltage that likelihood increasing an is there installed, the expectation of how much demand would LFDD Should distorted. is disconnected be be required operate, to it could disconnect lessdemand than expected meaning that the scheme would be less effective. In the worst case, if flows are reversed because the quantity of generation is greater than demand in the area, LFDD action could be detrimental and further increase the generation deficit. This was discussed in more detail in SOF 2016 November Framework Operability System Chapter five e a e te LFDD behaviour. an ongoing need to understand year-round is There working. currently is scheme the well how to understand Scotland in DNOs The same assessment is ongoing with the been. have would targets regional the of all not day, though particular this on met been Hence, the national LFDD target would have area. this in generation solar less is there as disconnected is demand the of 60% than more West, North the In area. this in generation PV solar distributed of amount the of because 60% below been have would West South the in disconnected day, demand the sunny the On Percentage ofdemanddisconnected Figure 5.16 system coordination Whole System OperabilityFrameworkNovember2016 u r u e r
u u provide a suitable year-round solution. to revised be can OC6 Code Grid that so medium-considering and long-term solutions is workgroup The round. year place in are required to ensure that robust arrangements still is work Further function. LFDD in disparities output might help to mitigate regional variability in demand and distributed generation term, investigations indicate that geographical short the In Scotland. to cover extended be to need also will which Wales, and England in distributed generation. Further work is required of output varying the against blocks demand the of availability the of understanding ayear-round support will which anticipated is work Further investigation. of stages initial its in still is group working ENA This Conclusions re r 170 Chapter five
171
in the power island during restoration. capability power Reactive The provider should be able manage to Dynamic frequency and voltage control control voltage and frequency Dynamic The provider should be able manage to large fluctuations in frequency and voltage requirements power reactive the involved in charging and energising and charging in involved network. transmission the loading Block The provider should be able manage to blocks demand of loading instantaneous is restored. and remain stable for these step changes as demand is reconnected, power islands are unified and whole system integrity system transmission the of Restoration shutdown regional or national a following is which approach coordinated a requires initiated and lead the by system operator. The current restoration strategy splits the country into Black Start zones. A number of providers are contracted within each zone for redundancy and increase to the probability of them being in state a of readiness. This is on the condition that it is economic and efficient for consumers, compared the to counterfactual of the capability not being available. power the as continues restoration Network islands grow and are synchronised together to this From network. transmission skeletal a form are power of levels increasing onwards, point restored as non-Black Start providers start-up and begin supply to energy the to system.
Background Black Start is the name given the to system recover to procedure contingency operator’s from the unlikely situation of a total or partial system transmission electricity the of shutdown which has caused an extensive loss of supply. It is an important part ofthe system operator’s insurance valuable a provides and toolkit policy for consumers in the unlikely event of a system failure. As set the by regulator, we are Start Black ensure capabilitywhich obliged to we deliver through our Black Start strategy. It is important that we ensure technically robust maintained and place in are arrangements restoration timely and safe a for allow which system. transmission the of Black Start capability is currently procured, as a service from providers that have the capability restartto from an on-site supply without reliance on external network supplies. These providers must be able energise to parts of the using network, distribution and transmission itself generator support the to demand local and extend to the created power island around the provider support to the start-up of other providers. energy In order maintain to this Black Start capability, been historically Start servicesBlack have technical had who generators from procured allowed which performance characteristics restoration be to carried out. Aside from the ability restart to without an external power supply, the capabilities required of a Black are: Start provider There is an ongoing requirement to develop Black StartThere is an ongoing requirement develop to strategy approaches system consider and alternative to to restoration. The providers Black Start of be more need to technology providers the futurein alternative andnew flexible are required enhance restoration the to options. 5.5.5 Black Start 2016 November Framework Operability System Chapter five desynchronise from the system more often. often. more system the from desynchronise and to synchronise likely are generators requirements increase, these thermal flexibility system the as that, demonstrate assessments Flexibility and Balancing Our merit. in delivered been not has maintained, as the market has meant the plant is capability Start Black that to ensure been has This to run. generators thermal large these to constrain actions taken has operator system increasing number of instances where the an been have there years, recent Over timescales. restoration expected the impacts turn in this and reduced greatly is deliver can it capability the warm, not is generator the If warm. be must generator To the this do within the requisite restoration timescales. reliably and effectively quickly, capability the to provide readiness of astate in are generators generation, it that is necessary these by thermal delivered is Start Black When market. by the periods where these units are not dispatched more challenging, there could be increasing conditions for other thermal providers become market If it. provide presently which those of capability Start Black the to replace aneed is closes in accordance with energy policy, there plant coal As strategy. restoration the with have inherent characteristics that have aligned they as role important an played have plants combined cycle gas turbines. Large thermal and coal stations with the later introduction of hydro of mixture –a fixed relatively been have Start Black of providers the years, twenty last the Over accordingly. strategy our adjust approach, foresee future requirements and existing our assess to continually have we where area an of example an is Start Black Discussion system coordination Whole System OperabilityFrameworkNovember2016 energy consumers. for delivered are solutions holistic efficient, that to ensure needs operability system other of context the in assessed be must strategy overlooked. Developments to Black Start be not should assessment of topics other under normal conditions, the interaction with likely to other requirements satisfy operability are strategy Start Black effective an delivering for required capabilities plant the Since consumers. for protection of level efficient and economic an to provide optimised are they that to ensure considered being are strategies approaches and sustainable restoration alternative term, long the In providers. by new supported being while warm to remain order in operation their in flexible more to become need providers existing that means This common. increasingly are market by the delivered are periods where few conventional providers Our Balancing assessments show that capability. Start Black maintain and strategy restoration the to support required are service Start aBlack of providers Alternative Conclusions employed. strategies restoration in and contracted providers in both approaches, new to consider aneed is there consumers, for secured economically is Start Black of To ensure the valuable insurance policy capability for longer timescales after running. merit, or who can maintain Black Start economic in to be likely are who providers new capability. There is therefore a requirement for their impact will this operation, their in variable more become providers existing as that clear the periods of constraint action were few, it is when cost-effective been have may approach existing our While action. operator system therefore will require capability Black Start future, the in on relied consistently be cannot Historical modes of base load operation
172
Chapter six
173 173 174
Conclusions and the way forward andConclusions way the six Chapter Chapter 2016 November Framework Operability System 2016 November Framework Operability System Chapter six be needed over the next few years. few next the over needed be and and when other services solutions will stronger signals to the market about what to provide intended is It decisions. investment information to facilitate commercial and clearer for request to your to respond this doing We are industry. the from feedback and requirements near-term specific with SOF the medium- and long-term technical analysis from operability. This document will combine the additional commercial information on system to give document anew publish will we time, first the for spring, the In months. coming the over provide will we that information of series in a part first the just is SOF The forward way The identified. requirements the to address industry the from feedback with analysis this combine now will We insight. flexibility and Scenarios Future to the Energy according change will needs those how and needed is it when needed, is what of picture detailed a more built have we support, your year, with This consumers. energy GB for works which system electricity carbon low flexible, amore to achieve met be must requirements appraisal and solutions identification. These options of aprocess to enable order in before ever than requirements clearer out set We have facilitate this future. capabilities from the whole system to to rules, tools and assets which unlock developments consider must we change, requirements consumers. As operability for value best provide which resources solutions across networks and energy coordinated and affordable efficient, requires The transition to a low carbon economy Conclusions Conclusions the way and forward System OperabilityFrameworkNovember2016 , with enhanced additional balancing
SOF the in identified requirements operability the provide a clear direction of travel which allows will It markets. services balancing the of welfare social the increase to providers, for field playing level amore with to market route the improve will work This industry. the with engagement significant involve will initiatives These to numerous parties. services their to offer participants market allow to industry the with framework services shared a establishing investigating We are market. the of all commercial and technical parameters to value the communicate and identify best we how to determine is This procurement. their for methods available all reviewing and defined of how are our services balancing and ancillary view aholistic taking We are to entry. barriers provide, making it more digestible and reducing we information the to improve We intend participants. to market signals these to deliver underway initiatives of anumber We have consumer. end the for costs down drive and to markets competition more investment and operational signals can bring better through transparency Greater to the industry. transparent more requirements our makes that working of way anew towards astep be will requirements are changing. This document decentralisation and digitisation, our for the end consumer. With decarbonisation, value to deliver objective overriding an with parties, existing and new to both accessible We aim to develop solutions which are to be addressed. to be
174 Chapter six 175 Markets and procurement Assets Codes and frameworks Transparent Transparent signals to market the
Industry feedback Near-term Near-term operational requirements System System Operability Framework Figure 6.1 The way forward 2016 November Framework Operability System Chapter six System OperabilityFrameworkNovember2016 176 Chapter seven 177 178 184 Appendix 2 – Glossary
Appendix 1 – Balancing methodology
seven Chapter Chapter 2016 November Framework Operability System Chapter seven Reference dayselectionfor7April2017 Figure 7.1 data. historical of years eight last the from random at past the from day reference asimilar allocated was 2026 31 March 2016 to 1April the from day each Firstly, requirement. flexibility operational an and data FES with this combining and past the from days reference similar selecting on credible half-hourly dataset was based a to produce used we method The methodology Balancing 7.1 methodology Balancing 1 Appendix System OperabilityFrameworkNovember2016 Bank holidays
2009 2016 2015 2013 2010 2012 2014 2011
GMT 30 March 30 29 March 25 March 28 March 28 26 March 26 27 March 27 25 March 25 27 March 27 Similar
All Fridayswithin14days 3 April 4 April 5 April 6 April 1 April 2 April 3 April Selected for Friday 7 April 2017. 7April Friday for day areference for process selection 7.1 Figure the of example an shows Reference day specification:
in the same time zone (GMT or BST). or (GMT zone time same the in holiday abank is day target the if only and if holiday, a bank week the of day same the ±14 date within target the of days 10 April 10 13 April 13 10 April 10 12 April 12 11 April 11 8 April 9 April 20 April 20 19 April 19 18 April 18 16 April 16 15 April 15 17 April 17 17 April 17
178 Chapter seven
179 in the modelling. the in profiles.We accounted for growth in distributed applied we which to capacities solar and wind Figure conditions. solar and wind reference the shows the projected7.2 transmission demand profiles for a week in Augustand the2016 based. were they which upon days reference The range is shown the by thickness of each line. Discontinuities at midnight each day are caused the by reference day method which spanned which assessments that meant midnight needed account to for this artefact
e e en e e e en e . The remaining days are similar days, from 1
ns ss n e n e n ns ss n Demand profiles, which are driven by coordinate behaviour of energyand theconsumers, consequent are timenoticeably of darkness. affected by daylight saving time which 9 April was selected 2010 at random. This process was repeated for every day in the period. assessment From each of the reference days, the demand profiler thentook the transmission demand profile and weather conditions (wind speeds across points various from insolation) and the country. used We the trends in the FES projectto the future transmission demand 1 Figure 7.2 demand projections, showing a range across all four scenarios Transmission Of all days the Fridays ofApril 7 within 2017 ±14 in the historical dataset, seven are excluded because they are bank holidays and the target date is not a bank holiday. Five are excluded because they are in GMT while is in 7 April 2017 BST 2016 November Framework Operability System Chapter seven chain is structured, using the probabilities Markov the how 7.4 Figure unit. demonstrates to each days ‘breakdown’ unexpected of Markov chain method to assign a number a use we outages, these of Outside outages. planned of cycles observed on based was This type. fuel its on depending unit each for made was outages planned of aprogramme assessment, the of start At the Availability SOF projectionofsummerminimumdemandversusoutturn(7August2016) Figure 7.3 detail in 2016 discussed 7August is The it. compared 2016, have we for to which minimum summer actual the as same the to be happens 7.3. 2016, 7August Figure date, in The shown SOF by the projected 2016 for demand minimum summer The methodology Balancing 1 Appendix System OperabilityFrameworkNovember2016
ns ss n e n SOF demand profiler is is profiler demand pr e t ra e a e ar a ra e pr e t
each fuel type. for rates ‘fix’ and ‘breakdown’ observed available today. These were based on the becoming it of a12% only is chance there again today. If it was unavailable yesterday, available be will it that chance a99% is there shown, if a unit was available yesterday then example the In state. same the in remaining or ‘unavailable’ and ‘available’ of states two the between day) (per transitioning aunit of GMT. in presented are results the of all days, reference selecting when account into zone time took assessment the while that Note 53. page on in the Balancing case and study Operability tt r
180 Chapter seven 181
and high likelihood that Ireland that likelihood high and 1 a a a e would be experiencing similar conditions to GB, there is low likelihood that the Irish power assist. substantially could system renewable weather-sensitive the are third The and solar large of dispatch initial The generators. wind farms depended on the prevailing weather beyond increased be not could They conditions. in reduced only were and position, initial this times of severe over-supply. Specifically, this only occurred during the second iteration, after adjustments. interconnector The consequence of this was the days of power affects which output, renewable high prices, were not always aligned between the two models. This deficiency was resolved runningby a second iteration of the SOF interconnector adjusted which model dispatch flows if necessary. Forexample, on days of to leading output generation renewable high over-supply, the interconnector flows could be adjusted achieve to balance. Note that the island the and GB between interconnectors of Ireland were not included in these re- adjustments. Due the to relative size of the Irish system power
a a e balancing model and so was was so and model balancing
Irish peak load is approximately that 10% of the GB power system – Eirgrid Generation Capacity Statement – 2025: 2016 http://www.eirgridgroup.com/site-files/library/EirGrid/Generation_Capacity_Statement_20162025_FINAL.pdf 1 The programme of planned and unplanned and planned of programme The outages for each unit was then kept constant for all cycles of assessment. For example, if a unit was unavailable it would on July 23 2019, be unavailable on that day in each scenario and flexibility case (these are discussed in the main section). Balancing the of body generation Inflexible For the purpose of this assessment, there are three types of generation which were were which generation types of three are initially assumed inflexible to to some degree. The first are nuclear generators, which were set run to at full output when they were available. This was due their to preferred operating mode as a result of their design economics. operational and which interconnectors, the are second The transfer power between GB and other power systems according our to European economic model of power prices and transfer capacities. This model was run separately theto SOF not aware of some of the conditions applied, conditions. weather including as such Figure 7.4 availability daily for a generator’s Example of a Markov chain 2016 November Framework Operability System Chapter seven they had to operate at between 55% and 55% and between at to operate had they When BMUs were running in the model, 7. 6. 1. for presentation purposes. type fuel to simplified is but granularity, of level unit aper at methodology our 5. 4. Simplified generationdispatchprocess Figure 7.5 the from by information order’, provided was remaining units were dispatched, the ‘merit the which in order The requirement. flexibility operator asystem plus demand to meet The remaining generation was then dispatched Dispatchable generation methodology Balancing 1 Appendix 3 2 System OperabilityFrameworkNovember2016 3. 2. Water availability was not included as this was accounted for in the planned and unplanned availability of this generation type. cycle. neap and spring the and cycle tide the on modelled was state tidal The area. that in state tidal the of principal semi-diurnal lunar harmonic and the principal semi-diurnal solar harmonic. aprojection that This includes the and dynamics ofmodel the twice-daily position asimplified upon geographical based was their for lagoon) tidal accounted and stream (tidal generators marine of number small the of output The
Marine Gas (CCGT). Gas Gas (OCGT). Gas
Hydro Gas Oil GT. Oil Gas Coal. Biomass. FES . The merit order was applied by by applied was order merit . The 3 . 2 .
ter e t r a eather a t e ere e a tate r pea e e ter e t r ar e ar
t ra e ear r namely namely publications, operator system other of subject the are assessment of types These included. not were country the of regions between transferred be can power much how limit might that constraints network the Furthermore, zero. to down running or from up running as such It dispatched units without considering factors it. after and before those of independently constraints; it optimised each settlement period The model did not include inter-temporal 55%. than higher no level output a minimum to have required are Code Grid to the subject 100% of installed capacity. Generation units for demand and flexibility. and demand for requirements the satisfies that units of number minimum the to dispatch was generation dispatch process. Its objective the of view 7.5Figure asimplified shows ETYS s e n t a terat terat a a e a a a ther and NOA and . a C a CC a a C a
182 Chapter seven
,
183
in times of over-supply. 5 Summer Outlook Report and Outlook Summer is not a security of supply assessment; SOF because they act optimise to the generation dispatch rather than act like a normal generator. service include modes operational Their operator, system the to either provision, network owners or other network users, or price arbitrage. Furthermore the complexity of modelling storage units is much greater The third was use to storage assets, which were not included in the initialdispatch than of generation due that to fact that its energy source is the power systemitself. a include must modelling storage Effective model of the storage volume inside the storage asset, so that the asset does not import more energy than it can store, nor export more energy than it had available at that time. As a result, storage units were only included in the generation dispatch as a penultimate penultimate a as dispatch generation the in was times these at assumption The step. that the storage units would have sufficient foresight hold to enough capacity import (to or export) for the period which followed and that the market prices around those periods incentivised them act to in ways which operability. supported system The very final step was a generic resource named ‘other balancing’. This is the gap between the expected generation dispatch at that time and the projected demand curve. This resource isexpected be to fulfilledby demand-side services or other developments in the industry. did We not explicitly model individual flexible demand services, such as Demand Up. This Turn approach allowed opportunities for a range of flexibility solutions background. neutral a from developed be to The The second step was constrain to wind, solar generation marine and this is the area of analysis covered the by Winter ReportOutlook published shortly before the relevant season. relevant the before shortly published
4
There was enough foresight that the initial initial the that foresight enough was There than favourable more was position market European the by set position initial the or model, interconnector The system operator had the capability issues, and issues, to tradeto capacity over the interconnectors effectivelyto address GB operability The connected systems were able accept to the changes that the market or the system operator requires. Other than by emergency instruction. emergency by than Other Of units that are visible to the system operator, this excludes most distributed installations. 4 5 Redispatch iteration Redispatch If supply and demand were not balanced by iteration second a iteration, initial the of end the was run. The following steps were used the by balancing algorithm as an approximation of a set of credible steps which might be taken by economic most the reality, In room. control the would operability met requirements that steps be taken. For example, in times of over-supply solar and wind constrained algorithm this output beforefilling storage, but in reality these and other steps might be taken in a prevailing the on depending order different conditions. market The first step of the redispatch wasto adjust the interconnector flows(except those between the island of Ireland and GB, for following The described). previously reasons made. were assumptions 1. 2. 2016 November Framework Operability System 3. Chapter seven EFCC GMT GG GC GB FOP FFCI FES ENTSO-E ENA ETYS DNO DSR DG DER CSC CP CHP CCGT CCS BST BMU BM ANM Acronym Glossary 2 Appendix System OperabilityFrameworkNovember2016 control capability Enhanced frequency Greenwich MeanTime Gone Green Grid code Great Britain Planning Future Operability current injection Fast fault Scenarios Future Energy operators –electricity transmission system European networkof association Energy networks year statement Electricity ten network owner Distribution Demand-side response Distributed generation resource Distributed energy converter Current source Consumer Power and power Combined heat gas turbine Combined cycle and storage Carbon capture British summertime mechanism unit Balancing Balancing mechanism management Active network Word Coordinated UniversalTime. Refers tomeansolartime atthevillageofGreenwich nearLondon,equivalent to One ofthefour2016future energy scenarios. between NGETandusersoftheNationalElectricity Transmission System. Sets outtheoperatingprocedures therelationship andprincipleswhichgovern A geographicalgrouping ofcountriesthatcontainsScotland,EnglandandWales. operability ofthegasnationaltransmissionsystem. Future OperabilityPlanningdescribeshowchangingrequirements affect the a voltagedeviation. Fast faultcurrent injection isthecurrent injectedduringandimmediatelyafter energy landscapeunderdifferent scenarios. The FESisanannualpublicationbyNationalGridwhichoutlinesthechangesin and givenlegalmandatesbytheEuropean Union’s Third LegislativePackage. ENTSO-E isanassociationofEuropean electricityTSOs.ENTSO-Ewasestablished licence holders. An industryassociationfundedbygasandelectricitytransmissiondistribution Transmission Systemoveraten-yearperiod andispublishedonanannualbasis. The ETYSoutlinesthefuture boundarytransferrequirements oftheNationalElectricity energy resources. Grid todemonstratetheprovision ofenhancedfrequency servicesfrom arangeof The 2014NetworkInnovationCompetitionproject awarded byOfgemtoNational in EnglandandWales andbelow132 One oftheownersnetworksbelowtransmissionvoltagelevel(below275 or gasconsumptionbrought aboutbyasignalfrom anotherparty. A changetoanindustrialandcommercial user’s ofmetered naturalpattern electricity network ratherthanthetransmissionnetwork. Distributed generationiselectricitygeneratingplantconnectedtoadistribution are generallysmallerthanthoseconnectedtothetransmissionsystem. Energy resources (generationordemand)connectedtodistributionnetworks,which A typeofpowerelectronic converterinwhichtheDCcurrent iskeptconstant. One ofthefour2016future energyscenarios. simultaneously inasingleprocess. A typeofpowerplantwhere bothusefulheatandelectricityare generated to generatemore electricity. used toproduce steaminaheatrecovery drivesasteamturbine boilerwhichinturn, drive asteamturbinetogenerateelectricity. Theresidual heatfrom thisprocess is A typeofgas-fired powerplantthatusesthecombustionofnaturalgasordieselto transported toastoragelocationandisolatedfrom theatmosphere. A process bywhichtheCO (GMT). hour aheadofGreenwich MeanTime During Britishsummertime,civiltimeintheUnitedKingdomisadvancedone controlled. of plantand/orapparatusthatisthesmallestgrouping thatcanbeindependently Units oftradewithintheBalancingMechanism.EachBMUaccountsforacollection The arrangementsusedtobalanceelectricitysupplyanddemandclosereal time. network utilisation. The control ofenergyresources according tothenetworkstatemaximise Description 2 produced inthecombustionoffossilfuelsiscaptured, kV inScotland). kV 184 Chapter seven 185 builds on the future boundary transfer requirements boundary transfer requirements Network Options Assessment builds on the future Description the national electricity transmission system to distribution A point of supply from customers. network owners or non-embedded the national gas transmission development of The GTYS illustrates the potential future and is published on an annual basis. system over a ten-year period power. The unit used to describe apparent masses which are in rotating stored The unit used to describe the energy system. and coupled to the power synchronised power. The unit used to describe reactive power. The unit used to describe real The benefit current. which used direct A type of power transmission technology distance losses (and cost) for long reduced of HVDC technology is generally power transfer. operational limits below drops when the system frequency A mechanism triggered disconnect demand to maintain system stability. to progressively is one of the principles of access used in an active network Last in first off when assigned based on the dates management scheme in which access rights are signed. connection contracts were capacity of less Defined within this document as generation units with an installed than 1 MW. it is produced where The network which transmits high-voltage electricity from It is owned and maintained by the country. it is needed throughout to where by transmission companies, while the system as a whole is operated regional a single system operator. The network investment recommendations. described in the ETYS to present scenarios. energy One of the four 2016 future the grid via a converter or control de-coupled from Generation technologies which are system and do not contribute to system inertia. Code. That portion of the Grid Code which is identified as the Operating power plant that uses the combustion of natural gas or diesel A type of gas-fired to drive a steam turbine to generate electricity. authority whose principal objective is independent national regulatory The UK’s consumers of electricity and gas. of existing and future the interests to protect system that generates an output signal with A phase-locked loop is a control to an input signal. phase related current it is a method of converting solar energy into direct In the context of solar PV, electricity using semi-conductor materials. for users who Grid Connection Codes that specify the requirements One of three that all new connect to electricity networks. RfG sets out the technical requirements to. electricity generators must adhere to time. with respect The change of frequency which can exist in a particular electrical system under The highest electric current conditions. short-circuit The minimum stable export operating level for BMU. An entity trusted with transporting energy in the form of natural gas or electricity on a National Grid operates the onshore national level using fixed infrastructure. or regional Britain. electricity and gas transmission systems in Great energy scenarios. One of the four 2016 future Grid supply point Year Gas Ten Statement power Apparent System inertia Reactive power Real power High voltage current direct demand Low frequency disconnection Last in first off generation Micro National electricity transmission system Network Options Assessment No Progression Non-synchronous generation Operating code Open cycle gas turbine Office of gas and electricity markets Phase-locked loop Photovoltaic Requirements for generator Rate of change of frequency level Short circuit Stable export limit System operator Slow Progression Word GSP GTYS GVA GVA.s Gvar GW HVDC LFDD LIFO MG NETS NOA NP NSG OC OCGT Ofgem PLL PV RfG RoCoF SCL SEL SO SP Acronym 2016 November Framework Operability System Chapter seven WPD UKPN TSO TO SVC SQSS SPTL SHETL STOR STATCOM Acronym Glossary 2 Appendix System OperabilityFrameworkNovember2016 Distribution Western Power UK PowerNetworks operator Transmission system Transmission owner Static varcompensator of supplystandards Security andquality Transmission Ltd Scottish Power Transmission Ltd Scottish Hydro Electric operating reserve Short term compensator Static synchronous Word maintains theelectricitylinesandcablesacross theMidlands,SouthWest andWales. One oftheelectricitydistributionnetworkownersinGreat Britain.Itownsand of England. maintains theelectricitylinesandcablesacross London,theSouthEastand One oftheelectricitydistributionnetworkownersinGreat Britain.Itownsand electricity andgastransmissionsystemsinGreat Britain. regional ornationallevelusingfixedinfrastructure. NationalGridoperatestheonshore An entitytrustedwithtransportingenergyintheformofnaturalgasorelectricityona An owneroftransmissionnetworkinfrastructure. A shuntdevicewhichusespowerelectronics tocontrol powerflowonthenetwork. offshore transmissionnetworks. The standard thatsetsoutthedesignandoperationcriteriaofonshore and electricity transmissionnetworkownersinGreat Britain. The nameusedinnetworkcodesandelsewhere torefer tooneoftheonshore electricity transmissionnetworkownersinGreat Britain. The nameusedinnetworkcodesandelsewhere torefer tooneoftheonshore demand reduction. A servicefortheprovision ofadditionalactivepowerfrom generationand/or Shunt devicewhichusespowerelectronics tocontrol powerflowonthenetwork. Description 186 Chapter seven 187
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document (‘the Document’) Document’) (‘the document The information contained within the System the within contained information The Operability Framework 2016 November Framework Operability System is disclosed voluntarily and without charge. charge. without and voluntarily disclosed is Operation System the replaces Document The section of the Electricity Year Statement Ten (ETYS) and is published in accordance with the relevant conditions. Licence the that emphasise to wish would Grid National information must be considered as illustrative only and no warranty can be or is made as the to accuracy within contained information the of completeness and Electricity Grid National Neither Document. this Transmission, National Grid Gas northe other companies within the NationalGrid group, nor the directors, nor the employees of any such company Disclaimer Chapter seven System OperabilityFrameworkNovember2016 188 Continuing the conversation
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