White Paper Integrating Small Solar Farms To The Grid: A .
White paperIntegrating small solar farms to the grid: a ‘smart’ guideManaging the solar floodThe construction of small solar farms isrunning ahead of grid integration rulesin many areas, and that can be a problem for utilities. In states where there isnothing like California’s trendsetting Rule21 in place to oversee the process – andFERC rules do not apply – utilities arefinding the best way to manage this solarflood is to “smarten” their transmissionand distribution grids. [1]By embracing the smart grid, utilities arenot only mitigating the technical difficulties associated with integrating solarfarms, they are also putting themselvesin a position to benefit from the enhanced stability and reliability renewablegeneration can provide. On a broaderlevel, investment in a smarter grid candirectly benefit ratepayers – through theuse of the most economic technologies,designs, and operating practices – whilealso helping states meet their renewableportfolio standard goals.So, to help utilities jumpstart the processof integrating small solar farms, this paperwill: a) identify issues their counterpartsaround the country have encountered; b)offer a brief guide to anticipating thoseissues, including questions to ask solardevelopers; c) provide some technicalguidelines along with; d) a glimpse ofthe future – and indeed some cautions.One point should be emphasized upfront: Any guidelines will require continualupdating in the face of constant technological change, pressure to meet state andlocal objectives for solar development,and real-world experience as the level ofsolar penetration increases.Yes, solar is differentUntil very recently, when distributedgeneration was added to distributionsystems, it was fossil-fueled,synchronous, and exhibited familiar
California Rule 21GuidelinesOnce the interconnection study has beenanalyzed and modeling completed, utilityengineers can begin to answer questions such asthese included in California’s Rule 21 [1]:1. Is the point of common connection (PCC)on a networked secondary system?2. Is certified equipment used?3. Is the starting voltage drop withinacceptable limits?4. Is the transformer or secondary conductorrating exceeded?5. Does the single-phase generator causeunacceptable imbalance?6. Is the short circuit current contributionratio within acceptable limits?7. Is the short circuit interrupting capabilityexceeded?8. Is the line configuration compatible withthe Interconnection type?9. Will power be exported across the PCC?10. Is the gross rating of the generatingfacility 11 kVA or less?11. Is the generating facility a net energymetering (NEM) generating facility withnameplate capacity less than or equal to500kW?12. Is the interconnection request for anarea identified as having current or future(due to currently queued interconnectionrequests) grid stability concerns?13. Is aggregate generating facility capacityon the line section less than 15% of linesection peak load for all line sectionsbounded by automatic sectionalizingdevices? The purpose of this screen issolely to determine whether the DER needsadditional study and is not intended asjustification for limiting the penetration ofgeneration on a line section.electrical characteristics. Not so withtoday’s solar inverter-based generation.“When presented with applications forthe integration of small solar farms, utilityengineers are finding they must dealwith an entirely new set of issues,” saysHoward Self, ABB’s Program Manager,Smart Grid Distribution Automation, “notthe least of which is whether they wantto control – or just monitor – these solarfacilities.”One key point: Utilities often lack control over when and where solar farms aresited. As such, distributed generators areoften clustered, resulting in a higher-thanaverage penetration on individual distribution feeders. And as a California EnergyCommission report notes, the effectsof clustering relate to the distributionsystem’s “functional connectivity,” not justgeographic proximity, and “therefore maynot be obvious to outside observers.” [2]“This means that the connection of solarfarms to the distribution grid can have amassive impact on existing equipment,especially distribution transformers – animpact that can be obscured in the rushto go green,” Self said.Minimizing the impactThe integration process generally beginswhen the solar developer submits aninterconnection study describing theproject in detail. This report will includegeneration and control equipment as wellas interconnection points, whether suchequipment is “certified,” and whetherthe generator will connect using theutility’s equipment (cables, transformers,switches, etc.) – even if that equipmentis behind the meter. If the developerintends to use utility equipment, an“added-facilities” contract may berequired, and that could give the utilityadditional control over the project. Atthat point, the utility begins its own duediligence. “This includes analyzing thesite and modeling various generatingscenarios to determine the impacts ontheir grid,” Self said.Once the interconnection study hasbeen analyzed and modeling completed,utility engineers can begin to answerinitial questions such as those included2 Integrating small solar farms to the grid ABB white paperin California’s Rule 21 (See Sidebar:California’s Rule 21) .As noted earlier, one of the first thingsutilities need to consider when integrating small solar farms is not just howthey are going to connect to them butalso how they are going to isolate themwhen necessary. “Many times powerfrom renewables will go to one or moretransformers before it’s distributed,” saidDoug Voda, Medium Voltage Smart GridSegment Leader, ABB. “It’s far betterto aggregate the power and then bringit onto the network through a singletransformer, so it can be controlled andisolated more effectively. If you don’t doit this way, you’ll have a lot of issues withpower factor and power quality.”Further, “if the utility can affect the choiceof inverters used on small solar farms,it’s better to use string inverters andaggregate power at one node,” continuedVoda. “String inverter technology hasimproved dramatically in the last four orfive years.”Next, said Self, “it is critical for utilityengineers to determine – among otherthings – whether their distribution transformers, feeders, and other equipmenthave sufficient capacity to accommodatethe additional generation from these smallsolar farms.”Make no mistake, integration issues increase with the size of the solar farm.“If we’re dealing with a 1 MW farm,”Voda said, “the whole network is affected, and utilities should be concernedwith system-wide protection schemes,coordination, SCADA, etc. But smallerfarms, those adding a few kW of powerto the grid, will generally not causesignificant disruptions.”The ideal approach, Voda said, “is tomodularize the solar farm, buildingit in increments, and adding stringinverters as you go along to get thevoltage you want.”But no matter how the solar farm is developed, one of the biggest challenges isthe high learning curve utilities face whenthey take over. How is it going to res-
pond to loads? How will the utility handleintermittency? How much to reducepower output and for how long? Whento take or dump power? All these thingsneed to be discussed and planned. (SeeSidebar: “Questions Utility EngineersShould Ask.” )Anticipating the new standardsIEEE’s 1547 series of standards (Figure 1)provides a set of requirements, recommended practices, and general guidancefor interconnecting distributed energyresources (DERs), including small solarfarms. Three-quarters of the states –along with numerous rural electric co-opsand municipal utilities – have adopted,referenced, or incorporated IEEE 1547 intheir own interconnection rules. But asthe National Renewable Energy Laboratory points out, advances in smart gridtechnology and the development of advanced DER/grid operations and controlsfunctionalities “are surpassing the requirements in current standards and codesfor DER installations and interconnectionwith the distribution grid.”[3]The good news is that a full revision ofIEEE Interconnection Standard 1547 isunderway, including corresponding 2030documents, which focus on communications and information technologies thatprovide interoperability for the integrationof DER. These new standards, which aredue to be issued in 2018, will establishrequirements, recommended practices,and guidance for advanced DER interconnections, smart grid interoperability,and a more robust grid overall. (SeeSidebar: “How the New 1547 Will EffectDistribution DER” .)Ensuring interoperabilityInteroperability is the ability of gridcomponents to communicate to oneanother through common protocols andstandards-based application programinterfaces (API). When it comes tointegrating DER, new systems andcomponents must be interoperable –not only with each other but also withlegacy systems and components. Ideally,utilities should be able to integrate DER –including solar, wind, and energy storage– in varying sizes, in numerous locations,IEEE Std 1547TM (2003 and 2014 Amendment 1)Standard for Interconnecting Distributed Resources with Electric Power SystemsIEEE Std P1547TM (full revision)Draft Standard for Interconnection and Interoperability of Distributed Energy Resources withAssociated Power Systems InterfacesIEEE Std 1547.1TM (2005)Standard for Conformance Tests Procedures for Equipment Interconnecting DistributedResources with Electric Power SystemsIEEE Std P1547.1aTMDraft Amendment 1IEEE Std 1547.2TM (2008)Application Guide for IEEE 1547 Standard for Interconnecting Distributed Resources withElectric Power SystemsIEEE Std 1547.3TM (2007)Guide for Monitoring Information Exchange, and Control of Distributed Resources withElectric Power SystemsIEEE Std 1547.4TM (2011)Guide for Guide for Design, Operation, and Integration of Distributed Resources withElectric Power SystemsIEEE Std 1547.6TM (2011)Recommended Practice for Interconnecting Distributed Resources with Electric PowerSystems Distribution Secondary NetworksIEEE Std 1547.7TM (2013)Guide to Conducting Distribution Impact Studies for Distributed Resource InterconnectionIEEE Std P1547.8TMDraft Recommended Practice for Establishing Methods and Precedures that Provide Supplemental Support for Implementation Strategies for Expanded Use of IEEE Std 1547-2003Figure 1: IEEE’s 1547 Interconnection standards. [4]and from a variety of vendors with theiradvanced distribution managementsystems (ADMS) and supervisory controland data acquisition (SCADA) systems.But clearly, this is easier said than done.According to EPRI’s “Common Functionsfor Smart Inverters, Version 3” report,utilities face two slightly different issues: [4]Questions UtilityEngineers Should AskThese may be basic, but they are critical tosmooth integration and a good place to startorganizing your approach to solar integration. Asoutlined in a report by Georgia Power and ABB [6]: What are utility and installer responsibilities?1. There are no common, standardsbased communication protocols thatallow products from multiple vendorsto be integrated in a distribution system in any manageable way. Andwithout these protocols, there is nointeroperability.2. There is no common view of thespecific functionality, or services,that these products would provide.According to EPRI, which conducted anumber of DER integration demonstrationprojects, the second of these points isthe more significant. “Although manufacturers all provided [inverters with] SmartGrid or grid-supportive functionalities,each did so in different or proprietaryways, making a system of diverse resources unmanageable.” For example, EPRInoted, every inverter maker offered VAR What is the solar facility‘s maximum output? What is the feeder minimum load? Is the connecting transformer configuration:wye, delta, wye-grounded, etc.? What type converter will be used: UtilityInteractive or Utility Independent? Is there other generation on the same feeder? What type of protective device(s) will beinstalled at the utility interface? What is the feeder reclosing sequence? What is the interaction with the automaticrestoration scheme? Will protective devices be owned by the utilityor the customer? Will a communications-aided protectionscheme be necessary? How will proper operation of protectiveequipment be verified?ABB white paper Integrating small solar farms to the grid 3
How the new 1547 willeffect distribution DERThe full revision of 1547 is addressingdistribution-level connected DER, including: [4] Generation and storage, including storage asa load Advanced functionalities of both DER andmodern grid equipment Distribution-transmission impacts and crossharmonization of requirements DER supplying adequate inertia for the grid Microgrids Very high penetration of renewables andother DERs Intermittency and uncertainty of renewablegeneration Two-way communications, controls, anddispatchability Interoperability and intelligent devicesintegration Demand response and load effects Potential interactive effects among advancedrequirements and specifications Introduction and incorporation of advancedevaluation and testing approaches suchas enhanced modeling and simulationrequirements Consideration and acceptance of powerhardware in the loop and control hardware inthe loop technology Potential requirements and specificationsfor considering evaluations of reliability andresiliency of DER-grid interconnections.support, but lacking any standard, eachprovided the support in a different way.[3] So, until new standards make interoperability easier, utilities facing a flood ofapplications for the integration of smallsolar farms, are best advised to: Select platforms that are both: a)compatible with current systems andb) flexible enough to adapt to futureimprovements, including remoteupdating. Understand the autonomous functionsprovided in the inverters to insure theymeet your immediate and future needs. Test the autonomous functions toinsure they provide the dynamicresponse (i.e. voltage, watt, VAr)support necessary across your system. Witness-test everything beforeinstallation. Continually monitor their input (volt,watts, VArs) to the system after installation to insure proper performance. Partner with vendors who understandyour system and can help you grow.Organizing the challengesThe principal challenges utilities facewhen integrating small solar farms fall intofour general categories – 1) synchronization, 2) circuit protection, 3) modeling,and 4) communications – which may beviewed as either time-related coordinationissues or distance/geography-related4 Integrating small solar farms to the grid ABB white papercoordination issues. This means utilitieswill control a huge variety of grid components that operate under a very broadrange of time constraints – from microseconds, the level at which solid-stateswitching devices operate, to the yearsit may take to bring new transmissionresources online.Time-related control issuesBalancing load and generation: Inthose areas of the country where utilitiesare facing the integration of thousands ofMW of solar generation, it’s clear they arealso dealing with a number of issues thattheir systems were not designed or builtto handle. Key among them, of course,is intermittency, which can affect electricdemand, storage, power balancing, andsynchronization. In principle, intermittency can be addressed with firming resources, including: Reserve generation capacity Dispatchable generation with highramp rates Generation with regulation capability Dispatchable electric storage Electric demand response (DR)To rely on firming generation, however,utilities require: a) real‐time, minute-byminute weather forecasts as well as themeans to translate those forecasts intogrid action. One way to do that is to
install an advanced distribution management system (ADMS) that not only executes weather and load forecasting but canalso run demand-response (DR) programsto curtail load when necessary.Dynamic behavior and grid stability:As noted earlier, inverters differ from conventional generators in that they producealternating current through the rapid on/off switching of solid-state circuits, buttheir dynamic effect on AC systems is notwell understood. As the California EnergyCommission report noted, utilities wouldbenefit from further research into thedynamic behavior of generation units onvoltage and frequency stability. [2]Distance/geography-relatedcontrol issuesWhen non-utility-owned DER are connected to the grid – and especially whensuch resources are clustered – they canlead to distance/geography-relatedcontrol issues, including feeder andtransformer capacity, distribution circuitprotection, and voltage regulation.Hosting capacity: Certainly, the determination of hosting capacity of distribution feeders is critical to measuring theirability to support new DER integration,and that ability is a function of DERtechnology, size, location, and feedertopography. While utilities traditionallyhave determined hosting capacity “byperforming detailed analyses of selectedfeeders and applying the results unilaterally across their system, assumingthat all feeders perform similarly,” thatmay not be entirely accurate, says EPRI.“Research has demonstrated significantvariation in hosting capacity among distribution feeders, even when they appearsimilar in construction.” [5]Transformer capacity: Can existingtransformers handle the increase in generation from DER?Protection: As the number of solarfarms on a system increases, thecomplexity of protection coordination andmodeling increases dramatically, forcingutilities to consider innovative protectionstrategies. For instance, fault currentproduced by inverter-based generation istypically higher than that from traditionalgeneration – but for much shorter timeperiods (2-4 times rated current for0.06 – 0.25 cycles), rendering traditionalprotection schemes unsuitable forrenewables. “While some good work hasbeen done in this area, there seems tobe not enough clarity on how PV shouldbe modeled,” a Georgia Power/ABBstudy concludes. [6](See Sidebar: “AnInnovative Protection Scheme”)Modeling: The grid views distributedgeneration (DG) in terms of net load,which means that neither the utility northe system operator may be aware ofactual generation or total load at anygiven time. Without this information, itABB white paper Integrating small solar farms to the grid 5
is impossible to construct an accuratemodel of local load to either forecastfuture loads, including ramp rates, or toascertain system reliability and security ifthe DG fails. [2]Voltage regulation: By changing localload, DER directly affects voltage alongdistribution feeders, potentially sendingvoltage to levels outside the permissible range and, thereby, creating a needfor voltage regulation. Of course,that in turn can lead to overuse ofvoltage regulation equipment. Onecaution: In some instances voltageprofiles may not be seen by systemoperators, so enhancing situationawareness by system operators isvital. Finally, DER can create a needfor reactive power (VAr) support.according to Adam Guglielmo, Director ofBusiness Development for ABB WirelessCommunication Systems, when utilitiesare integrating multiple solar farms, theyneed to look at the issue holistically, notone project, at a time.“Utilities should look for a communicationsystem that will meet the requirementsof all the applications they will carry overtime as opposed to one specific appli-Energy storage will be indispensableOf all the issues involved in integratingsmall solar farms, intermittency – and theproblems it creates for grid stability, reliability, and safety – is often paramount.That makes energy storage an importantnext step in the evolution of the smartgrid. “While energy storage isn’t a criticalelement at the grid level just yet,” said P
IEEE Std P1547.8TM Draft Recommended Practice for Establishing Methods and Precedures that Provide Sup-plemental Support for Implementation Strategies for Expanded Use of IEEE Std 1547-2003 IEEE Std P1547.1aTM Draft Amendment 1 Figure 1: IEEE’s 1547 Interconnection standards. [4] IEEE Std P1547TM (full revision)
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