This work proposes recommendations for new guidelines for fault current injection on a distribution grid. These guidelines will help improve the transition towards renewable electrical energy generation. The grid-integration of inverter-based distributed generations (IBDGs) into the distribution grid changes the topology of a conventional grid with one-way power flow to a grid with multi-way power flow. This thesis investigates the impact of fault current injection on a distribution grid, if the limitations in the fault current injection of IBDGs affect the reliable function of the protection system and if there is a preferable type of current control to be prioritised. This investigation was carried out through a literature review and transient state simulations on a model grid in PSCAD. The grid is based on a real radial distribution grid on the Swedish island of Gotland, where a Type III wind turbine generator (WTG) is connected. The limitation on fault current injection by the wind turbine, the location and type of fault in the grid, can affect the reliable function of the protection system. The control system inside a type III WTG affects its fault current injection that impacts fault detection by the protection system. This thesis emphasizes the need for a guideline and requirement on the WTG control system for fault current injection. Prioritising reactive current control (q-axis) seems to be preferable and should become the standard for fault current injection in type III wind turbine generators in this distribution grid, according to this study. Furthermore, the need for more investigation for different types of IBDGs with different control strategies is highlighted in this work. / Detta arbete föreslår rekommendationer för nya riktlinjer för felströmsinjektering i ett distributionsnät. Dessa rekommendationer kommer bidra till att förbättra omställningen till förnyelsebar elgenerering. Integreringen av omriktarbaserade distributionsgeneratorer (IBDG) i distributionsnätet förändrar topologin i ett konventionellt nät med ett enkelriktat effektflöde till ett flervägsriktat effektflöde. Detta examensarbete undersöker påverkan av felströmsinjektering i ett distributionsnät, om begränsningarna i felströmsinjekteringen hos IBDG:er påverkar reläskydds pålitliga funktionalitet och om det finns en typ av kontrollström som föredras och bör prioriteras. Denna undersökning genomfördes genom en litteraturstudie och transienta simuleringar i ett exempelnät i PSCAD. Nätet är baserat på ett verkligt radialdistributionsnät från Gotland, där ett Typ III vindkraftverk (WTG) är anslutet. Begränsningen i felströmsinjektering hos vindkraftverket, platsen för och typen av fel i nätet kan påverka den pålitliga funktionaliteten hos reläskydd. Kontrollsystemet inuti ett Typ III WTG påverkar dess felströmsinjektering som påverkar feldetekteringen i reläskyddet. Detta examensarbete betonar vikten av riktlinjer och krav på WTG kontollsystem för felströmsinjektering. Prioritering av reaktiv kontrollström (q-axis) verkar vara fördelaktigt och bör bli standard för felströminjektering i Typ III WTG i detta distributionsnät, enligt detta arbete. Dessutom påtalas behovet av att ytterligare undersöka olika typer av IBDG:er med olika kontrollstrategier i detta arbete.

The Swedish electricity system is transitioning due to the establishment of climate policy goals and trends related to technology and demographics. The transition has resulted in an increased demand for electricity. The increased demand for electricity in combination with lack of forecasts, planning and coordination between actors in the electricity sector has led to the occurrence of grid congestion. Extending the network is time-consuming and requires substantial investments. Instead, an alternative is to utilise the available grid capacity more efficiently by implementing flexibility solutions. Flexibility can be achieved by implementing incentives such as grid tariffs. This solution has recently gained much attention in Sweden, but it is not apparent how grid tariffs should be designed. The purpose of this thesis is to investigate how distribution grid tariffs could be designed to incentivise different actors to contribute to flexibility in a way that results in an efficient use of the electrical grid. A qualitative study was performed, collecting empirical data through semistructured interviews with actors in the Swedish electricity market. The aim is that the results from this thesis will act as a basis for DSOs planning to design grid tariffs with the purpose to utilise the grid more efficiently. The findings present a ToU capacity charge with off-peak periods that are free of charge as the preferable main price signal in the tariff to achieve efficient utilisation of the grid. It is further argued that other structural elements can complement the ToU capacity charge. A small fixed charge could be added in order to contribute to the cost reflectiveness of the grid tariff. A small energy charge could be incorporated in order to provide consumer with incentives to be flexible below the current metered maximum power and strengthen the signal from the ToU capacity charge. A small energy charge can avert difficulties related to providing incentives below the current metered maximum, as it still can provide some incentives to be flexible, or strengthen the signal from the ToU capacity charge. Further, the energy charge can ensure sustainability if customers respond well to a ToU capacity charge and to compensate solar PV customers. Furthermore, recommendations to further enable the grid tariffs potential to provide price signals include shifting the focus of the revenue cap from CapEx to OpEx and exploring the hampering signals of the energy tax as well as contradicting price signals from the wholesale electricity price. / Det svenska elsystemet genomgår en förändring till följd av införandet av klimatmål och trender relaterade till teknik och demografi. Denna förändring har resulterat i ett ökat effektbehov. Ett ökat effektbehov i kombination med bristande prognostisering, planering och samordning mellan aktörer inom elsektorn har lett till uppkomsten av kapacitetsbrist. Att bygga ut elnätet är tar tid och kräver större investeringar. Ett alternativ är att istället utnyttja det befintliga elnätet mer effektivt genom att implementera flexibilitetslösningar. Flexibilitet kan uppnås genom att införa incitament i form av elnätstariffer. Denna lösning har nyligen fått mycket uppmärksamhet i Sverige, men det är inte klart inte hur dessa elnätstariffer ska utformas. Syftet med detta arbete är att undersöka hur distributionsnätets tariffer kan utformas för att stimulera olika aktörer att bidra med flexibilitet på ett sätt som resulterar i en effektiv användning av det befintliga elnätet. En kvalitativ studie genomfördes där empiriska data samlades in genom semistrukturerade intervjuer med aktörer på den svenska elmarknaden. Syftet är att resultaten från detta arbete ska fungera som ett underlag för nätägare som planerar att utforma elnätstariffer med syftet att utnyttja nätet mer effektivt. Resultaten visar att en ToU-effektavgift med gratis off-peak perioder bör vara den huvudsakliga prissignalen i en elnätstariff som ämnar att utnyttja det befintliga nätet mer effektivt. Det visar även att andra strukturella element kan komplettera ToU-effektavgiften. En mindre fast avgift kan adderas i syfte att göra elnätstariffen mer kostnadsriktig. En mindre energiavgift kan införas för att ge kunder incitament att vara flexibla även under den nuvarande uppmätta maximala effekten och stärka signalen från ToU-effektavgiften. Vidare kan energiavgiften säkerställa tillräckliga intäkter för nätägaren om kunderna svarar bra på en ToU-effektavgift och för att kompensera kunder med solceller. Ytterligare rekommendationer för att möjliggöra prissignaler genom elnätstariffer inkluderar att skifta fokus på intäktsramen från CapEx till OpEx och utforska de hämmande prissignalerna från energiskatten och de motstridiga prissignalerna från elhandelspriset.

This Master´s thesis deals with problematics related to the connection of new decentralized power sources into electrical power grid. Due to advantageous legislative support of these new, especially photovoltaic power sources, a massive amount of these sources have been connected into the power grid between years 2009 and 2010. For theoretical understanding of processes during a steady-state, the initial parts of this paper are focused on a procedure which solves steady-state on every power line mentioned. When we speak of decentralized power sources connection, it is necessary to mention the connected legislative. National distribution grid operators in collaboration with national regulatory commission have decided on a legislative document Rules of distribution grid operation, which puts a set of demands and requirements on applicants wishing to connect a new power source to the grid. The text of this thesis is focused mainly on demands required after the latest change in 1/2010. Practical part of this work deals with verification of new power source influence on a related power grid and meeting the legislatively required demands. The most important demands are voltage change due to new power source operation and its transfer to other voltage levels, higher harmonics injection, power output fluctuation and last, not least, changes in load flow directions. For reasons previously mentioned an analysis is made and possibilities of reducing or removing of these influences are introduced. To achieve these goals, two computer programs, Siemens Sinaut Spectrum and NetCalc are used.

Zur Umsetzung der Energiewende ist in den kommenden Jahren ein substantieller Netzausbau notwendig, der jedoch regional unterschiedlich stark ausfallen wird. Nach gegenwärtiger Gesetzeslage werden die folglich sehr unterschiedlich hohen Netzkosten von den Endkunden des jeweiligen Netzgebietes über die Netznutzungsentgelte getragen. Mittels eines detaillierten Modells der Kostenbestandteile der Netzkosten in den einzelnen Regionen wurden unter Berücksichtigung des erwarteten Netzausbaus sowie der demographischen Entwicklung die Netznutzungsentgelte, geschlüsselt nach den Kundengruppen Haushalt und Gewerbe sowie Industrie bis zum Jahr 2023 prognostiziert. Die anschließende Analyse eines bundesweiten Wälzens von Übertragungs- und Verteilungsnetzbestandteilen der Entgelte kommt zu dem Ergebnis, dass in Zukunft neben den ostdeutschen Flächenländern auch die Küstenländer Schleswig-Holstein und Niedersachsen sowie Teile Bayerns von einem bundeseinheitlichen Entgelt profitieren würden. Dabei stellt sich eine asymmetrische Verteilung von Be- und Entlastungen dar. Den zum Teil erheblichen jährlichen Entlastungen von bis zu 130 EUR pro 3-Personenhaushalt stehen in den süd- und westdeutschen Flächenländern vergleichsweise geringe Mehrbelastungen von maximal 30 EUR gegenüber. Gleichzeitig zeigt die Analyse, dass ein alleiniges Wälzen der Übertragungsnetzkosten zum heutigen Stand für Industriekunden in Ostdeutschland zwar merkliche Entlastungen mit sich bringen würde, diese aber zukünftig abnehmen und im Haushaltskundenbereich sehr gering ausfallen. Insgesamt lässt sich aus den Ergebnissen der Analyse schlussfolgern, dass die regionale Ungleichverteilung der Netzkosten tendenziell zunimmt und es Regionen in Deutschland gibt, in denen hohe Netzausbaukosten, eine negative demographische Entwicklung und eine geringe Kaufkraft zusammentreffen und so Privathaushalte sowie Industriebetriebe stark belasten.

Der zur Umsetzung der Energiewende notwendige Netzausbau fällt regional sehr unterschiedlich hoch aus. Durch die bestehende Entgeltsystematik ergeben sich hierbei potentielle Mehrbelastungen für Stromkunden in Regionen mit einem hohen Anteil an Erneuerbaren Energien. Aktuell sind vor allem in den neuen Bundesländern höhere Entgelte zu verzeichnen. Im Rahmen dieses Kurzgutachtens werden mittels eines detaillierten Modells der Netzkosten auf den unterschiedlichen Spannungsebenen nach Landkreisen aufgeschlüsselte Netznutzungsentgelte bis zum Jahr 2024 prognostiziert. Darüber hinaus werden fünf Anpassungsvarianten der bestehenden Entgeltsystematik quantitativ analysiert und diskutiert:  Einheitliches Übertragungsnetzentgelt  Streichung der vermiedenen Netznutzungsentgelte für dargebotsabhängige Erzeuger  Preiskorridore für Endkundenentgelte  Bundeseinheitliche Entgelte für Endkunden  Wälzen der durch Erneuerbare Energien (EE) bedingten Verteilernetzkosten Aus den Analysen ergeben sich vor allem für die Varianten Entgeltkorridore, bundeseinheitliche Entgelte sowie für das Wälzen der EE-bedingten Verteilernetzkosten signifikante Entlastungseffekte für Kunden mit sehr hohen Entgelten bei moderater Mehrbelastung der übrigen Stromkunden. Obwohl die letzte Variante zu einer verursachungsgerechteren Kostenverteilung führen würde, ist deren Umsetzbarkeit äußerst fraglich. Erste Maßnahmen um ein Auseinanderdriften der Entgelte abzuschwächen, die deutlich einfacher umzusetzen sind, wären die Einführung eines einheitlichen Übertragungsnetzentgelts sowie die Streichung vermiedener Netznutzungsentgelte für dargebotsabhängige Erzeuger.

Zur Umsetzung der Energiewende ist in den kommenden Jahren ein substantieller Netzausbau notwendig, der jedoch regional unterschiedlich stark ausfallen wird. Nach gegenwärtiger Gesetzeslage werden die folglich sehr unterschiedlich hohen Netzkosten von den Endkunden des jeweiligen Netzgebietes über die Netznutzungsentgelte getragen. Mittels eines detaillierten Modells der Kostenbestandteile der Netzkosten in den einzelnen Regionen wurden unter Berücksichtigung des erwarteten Netzausbaus sowie der demographischen Entwicklung die Netznutzungsentgelte, geschlüsselt nach den Kundengruppen Haushalt und Gewerbe sowie Industrie bis zum Jahr 2023 prognostiziert. Die anschließende Analyse eines bundesweiten Wälzens von Übertragungs- und Verteilungsnetzbestandteilen der Entgelte kommt zu dem Ergebnis, dass in Zukunft neben den ostdeutschen Flächenländern auch die Küstenländer Schleswig-Holstein und Niedersachsen sowie Teile Bayerns von einem bundeseinheitlichen Entgelt profitieren würden. Dabei stellt sich eine asymmetrische Verteilung von Be- und Entlastungen dar. Den zum Teil erheblichen jährlichen Entlastungen von bis zu 130 EUR pro 3-Personenhaushalt stehen in den süd- und westdeutschen Flächenländern vergleichsweise geringe Mehrbelastungen von maximal 30 EUR gegenüber. Gleichzeitig zeigt die Analyse, dass ein alleiniges Wälzen der Übertragungsnetzkosten zum heutigen Stand für Industriekunden in Ostdeutschland zwar merkliche Entlastungen mit sich bringen würde, diese aber zukünftig abnehmen und im Haushaltskundenbereich sehr gering ausfallen. Insgesamt lässt sich aus den Ergebnissen der Analyse schlussfolgern, dass die regionale Ungleichverteilung der Netzkosten tendenziell zunimmt und es Regionen in Deutschland gibt, in denen hohe Netzausbaukosten, eine negative demographische Entwicklung und eine geringe Kaufkraft zusammentreffen und so Privathaushalte sowie Industriebetriebe stark belasten.

Conventionally, to support varying power demand, the utility company must prepare to supply more electricity than actually needed, which causes inefficiency and waste. With the increasing penetration of renewable energy which is intermittent and stochastic, how to balance the power generation and demand becomes even more challenging. Demand response, which reschedules part of the elastic load in users' side, is a promising technology to increase power generation efficiency and reduce costs. However, how to coordinate all the distributed heterogeneous elastic loads efficiently is a major challenge and sparks numerous research efforts. In this thesis, we investigate different methods to provide demand response and improve power grid efficiency. First, we consider how to schedule the charging process of all the Plugged-in Hybrid Electrical Vehicles (PHEVs) so that demand peaks caused by PHEV charging are flattened. Existing solutions are either centralized which may not be scalable, or decentralized based on real-time pricing (RTP) which may not be applicable immediately for many markets. Our proposed PHEV charging approach does not need complicated, centralized control and can be executed online in a distributed manner. In addition, we extend our approach and apply it to the distribution grid to solve the bus congestion and voltage drop problems by controlling the access probability of PHEVs. One of the advantages of our algorithm is that it does not need accurate predictions on base load and future users' behaviors. Furthermore, it is deployable even when the grid size is large. Different from PHEVs, whose future arrivals are hard to predict, there is another category of elastic load, such as Heating Ventilation and Air-Conditioning (HVAC) systems, whose future status can be predicted based on the current status and control actions. How to minimize the power generation cost using this kind of elastic load is also an interesting topic to the power companies. Existing work usually used HVAC to do the load following or load shaping based on given control signals or objectives. However, optimal external control signals may not always be available. Without such control signals, how to make a tradeoff between the fluctuation of non-renewable power generation and the limited demand response potential of the elastic load, and to guarantee user comfort level, is still an open problem. To solve this problem, we first model the temperature evolution process of a room and propose an approach to estimate the key parameters of the model. Then, based on the model predictive control, a centralized and a distributed algorithm are proposed to minimize the fluctuation and maximize the user comfort level. In addition, we propose a dynamic water level adjustment algorithm to make the demand response always available in two directions. Extensive simulations based on practical data sets show that the proposed algorithms can effectively reduce the load fluctuation. Both randomized PHEV charging and HVAC control algorithms discussed above belong to direct or centralized load shaping, which has been heavily investigated. However, it is usually not clear how the users are compensated by providing load shaping services. In the last part of this thesis, we investigate indirect load shaping in a distributed manner. On one hand, we aim to reduce the users' energy cost by investigating how to fully utilize the battery pack and the water tank for the Combined Heat and Power (CHP) systems. We first formulate the queueing models for the CHP systems, and then propose an algorithm based on the Lyapunov optimization technique which does not need any statistical information about the system dynamics. The optimal control actions can be obtained by solving a non-convex optimization problem. We then discuss when it can be converted into a convex optimization problem. On the other hand, based on the users' reaction model, we propose an algorithm, with a time complexity of O(log n), to determine the RTP for the power company to effectively coordinate all the CHP systems and provide distributed load shaping services. / Graduate

Electricity grids require the ancillary services frequency control, grid operation, re-establishment of supply and voltage stability for a proper operation. Historically, conventional power plants in the transmission grid were the main source providing these services. An increasing share of decentralized renewable energy in the electricity mix causes decreasing dispatch times for conventional power plants and may consequently lead to a partial replacement of these technologies. Decentralized energy sources are technically capable of providing ancillary services. This work focuses on the provision of reactive power for voltage stability from decentralized sources. The aim is to answer the question of how voltage stability and reactive power management can be achieved in a future electricity system with increasing shares of decentralized renewable energy sources in an economical and efficient way. A methodology that takes reactive power and voltage stability in an electricity system into account is developed. It allows for the evaluation of the economic benefits of different reactive power supply options. A non-linear and a linearized techno-economic grid model are formulated for this purpose. The analysis reveals an increasing importance of reactive power from the distribution grid in future development scenarios, in particular if delays in grid extension are taken into account. The bottom-up assessment indicates a savings potential of up to 40 mio. EUR per year if reactive power sources in the distribution grid provide reactive power in a controlled manner. Although these savings constitute only a small portion of the total cost of the electricity system, reactive power from decentralized energy sources contributes to the change towards a system based on renewable energy sources. A comparison of different reactive power remuneration mechanisms shows that a variety of approaches exist that could replace the inflexible mechanisms of obligatory provision and penalized consumption of reactive power that are mostly in place nowadays.

The world is now in a transition towards a more sustainable future. Actions to reduce the green-house gases (GHG) emissions have been promoted and implemented globally, including switching to electric vehicles (EVs) and renewable energy technologies, such as solar photovoltaics (PV). This has led to a massive increase of EVs and PV adoption worldwide in the recent decade. However, large integration of EVs and PV in buildings and electricity distribution systems pose new challenges such as increased peak loads, power mismatch, component overloading, and voltage violations, etc. Improved synergy between EVs, PV and other building electricity load can overcome these challenges. Coordinated charging of EVs, or so-called EV smart charging, is believed to a promising solution to improve the synergy. This licentiate thesis investigates the synergy between residential EV charging and PV generation with the application of EV smart charging schemes. The investigation in this thesis was carried out on the individual building, community and distribution grid levels. Smart charging models with an objective to reduce the net-load (load - generation) variability in residential buildings were developed and simulated. Reducing the net-load variability implies both reducing the peak loads and increasing the self-consumption of local generation, which will also lead to improved power grid performance. Combined PV-EV grid hosting capacity was also assessed.       Results show that smart charging schemes could improve the PV self-consumption and reduce the peak loads in buildings with EVs and PV systems. The PV self-consumption could be increased up to 8.7% and the peak load could be reduced down to 50%. The limited improvement on self-consumption was due to low EV availability at homes during midday when the solar power peaks. Results also show that EV smart charging could improve the grid performance such as reduce the grid losses and voltage violation occurrences. The smart charging schemes improve the grid hosting capacity for EVs significantly and for PV slightly. It can also be concluded that there was a slight positive correlation between PV and EV hosting capacity in the case of residential electricity distribution grids.

This work describes an actual condition of a specific part of a distribution power grid. It is a research of problems based on the computer model in case some power line is in failure or shut down. Simulations are calculated for both currently used load and load expected in future usage. There are partial solutions depicted for each issue found during the simulation. Some of those are used for a final design of a distribution power grid. In the last section, there is a comparison of different types of power lines and their possible usage in the design.