Search

This paper presents a method to determine the optimal location, energy capacity, and power rating of distributed battery energy storage systems at multiple voltage levels to accomplish grid control and reserve provision. We model operational scenarios at a one-hour resolution, where deviations of stochastic loads and renewable generation (modeled through scenarios) from a day-ahead unit commitment and violations of grid constraints are compensated by either dispatchable power plants (conventional reserves) or injections from battery energy storage systems. By plugging-in costs of conventional reserves and capital costs of converter power ratings and energy storage capacity, the model is able to derive requirements for storage deployment that achieve the technical-economical optimum of the problem. The method leverages an efficient linearized formulation of the grid constraints of both the HV (High Voltage) and MV (Medium Voltage) grids while still retaining fundamental modeling aspects of the power system (such as transmission losses, effect of reactive power, OLTC at the MV/HV interface, unideal efficiency of battery energy storage systems) and models of conventional generator. A proof-of-concept by simulations is provided with the IEEE 9-bus system coupled with the CIGRE' benchmark system for MV grids, realistic costs of power reserves, active power rating and energy capacity of batteries, and load and renewable generation profile from real measurements., To be presented at PSCC 2020 and to apper in a future issue of Elsevier EPSR

Norway has implemented economic incentives over several years to encourage a transition from conventional vehicles to electric vehicles (EVs), and now has the largest share of EVs per capita in the world. This study explores the effects of increasing EV penetration levels in a Norwegian distribution grid, by using real powermeasurements obtained from household smart meters in load flow analyses, using the MATPOWER load flow package in MATLAB. The implications of installing a fastcharger in the grid has been assessed, and an optimal location for it is proposed, aiming at minimizing both grid losses and voltage deviations. Moreover, the potential for reactive power injection to reduce the voltage deviations caused by it has been investigated. Results show that the EV hosting capacity of the grid is good for a majority of the end-users, but that the weakest power cable would be overloaded at a 20 % EV penetration level. The network tolerated an EV penetration of 50 % with regards to the voltage levels at all end-users. Injecting reactive power at the location of an installed fast charger proved to significantly reduce the largest voltage deviations otherwise imposed by the charger.

The Parker project was a Danish demonstration project focused at Vehicle-Grid Integration (VGI). The primary aim of the project was to demonstrate that contemporary electrical vehicles could participate in advanced smart grid services including the use of Vehicle-To-Grid (V2G). Parker builds on two previous projects, the EDISON and Nikola projects, which already laid the foundation for understanding the electric vehicle’s potential in supporting the power system. The project utilized a number of contemporary electric vehicles and V2G DC chargers provided by its industrial partners and used them to carry out a number of tests and demonstrations in PowerLabDK - an experimental platform for power system research. Further, the project partnered with the world’s first commercial pilot (the Frederiksberg Forsyning V2G hub) where electric vehicles provided frequency containment reserve, located in greater Copenhagen. The project used the above assets to investigate three key topics: grid applications, grid readiness as well as scalability and replicability.

EV chargers can be controlled to support the grid frequency by implementing a standard-compliant fast Primary Frequency Control (PFC). This paper addresses potential effects on power systems due to control discreteness in aggregated electric vehicles (EVs) when providing frequency regulation. Possible consequences of a discrete response, as reserve provision error and induced grid frequency oscillations, are first identified by a theoretical analysis both for large power systems and for microgrids. Thus, an EV fleet management solution relying on shifting the droop characteristic for the individual EVs is proposed. The PFC is implemented in a microgrid with a Power-Hardware-in-the-Loop approach to complement the investigation with an experimental validation. Both the analytical and the experimental results demonstrate how the controller performance is influenced by the response granularity and that related oscillations can be prevented either by reducing the response granularity or by applying appropriate shifts on the droop characteristics for individual EVs.

Nowadays, power system operators face challenges in supporting a stable and economic future power system based on renewable energy production and new types of flexible demand, such as electric vehicles (EVs). One of the main challenges is to address the adverse effects that the EVs may have on local distribution grids (distribution system operator (DSO) perspective) and enhance their usage to optimize utilization of renewables on a national/regional scale (transmission system operator (TSO) perspective). The research emphasis of this thesis is on power and energy services that EVs can provide both locally and system-wide. Three main topics are addressed:1. Identification of current policies and barriers for system-wide and local grid service provision from EVs, as well as possible conflicts between TSO and DSO when acquiring such services. This problem comes from the TSOs’ need for grid stability services from small dispatched units, and the simultaneous interest of the DSO not to have power provision from distributed energy sources violating the local grid constraints. The acquisition of such flexibility services from one gridoperator may cause undesired effects to another operator: technical and economical conflicts may arise, and a detection and categorization strategy is proposed.2. Investigations on the suitability of standard-compliant commercial hardware (series-produced EVs and chargers) for the provision of uni- and bi-directional grid services, in order to detect the technical challenges related to EVs control for grid balancing purposes. This was the starting point for the development and implementation of standard-compliant control logics able to guarantee power system frequency stability both on a simulation and on a laboratory validation level. Possible smart EV control solutions are proposed, which aim at stabilizing frequency oscillations, at reducing reserve provision error, and at providing a trade-off between error and the overall efficiency of the fleet power converters. Further, system stability is studied both on a microgrid and on a full-scale power system level in order to outline requirements for the overall fleet output, to secure an aggregated response that does not harm the system stability 3. Identification of the technical impacts on the distribution system due to massive EV penetration levels and investigation of the effectiveness of reactive power provision from EV chargers. In general, reactive power modulation allows a reduction of the self-induced under-voltage conditions caused by EVs charging at distribution grid levels, but how effective is this solution in practice? An analytical study is conducted, which aims to assess reactive power provision from EVs in typical distribution grids. In conclusion, the research at a whole investigates the broad topic of EV integration from different stakeholders’ point of view, such as market operators, DSOs, TSOs and EV aggregators. The proposed solutions and control strategies are expected to significantly contribute to the real power system operation, in order to pave the way for a harmonic, economic and safe utilization of the increasing number of EVs.

In the EUDP project ‘Energy saving by voltage management’ two reports are provided by Technical University of Denmark (DTU) covering the simulation studies and experimental work. The first report presented the simulation results regarding the technical evaluation of on-load tap changers in solving the voltage problems in presence of photovoltaic distributed generation, using Bistrup distribution grid (DONG Energy) as a test case. This second report presents the experimental results of the testing activity of the Voltage Optimization Unit (VOU), i.e., a distribution transformer with single-phase on-load tap changers (OLTC) in an experimental low voltage grid. Both the transformer internal behavior and its effective operations under different unbalanced bidirectional power flow conditions have been investigated. Moreover, different control logics are analyzed based on their control objectives and control inputs, which include network currents and voltages that can be measured either locally or remotely. The experimental validation has been performed in the research infrastructure SYSLAB-PowerLabDK, a laboratory facility for the development and test of control and communication technology for active and distributed power systems, located at DTU Risø campus. The experimental test validates the control performance of the OLTC transformer and the test indicates that, using remote measurement, the voltage of the system can be kept in a safe operational band. However, the remote measurement implies additional cost investments of to the system operator, thus a proactive tap algorithm is developed and tested in this project, relying on local measurements. In addition, we also compared the experimental result with the one simulated in the DigSilent PowerFactory software environment (the software used in the first report), and the results show that the system components have been properly modeled. Note that the system tested in this report is a simplified network that cannot characterize all the features of a real distribution network, even though it is able to catch the most important ones. Future study could include two aspects: 1) investigate the OLTC’s application in an active distribution network characterized by several subfeeders, where higher penetration of different distributed generations is present; and 2) combine the OLTC control with smart-metering technology, where the measurements from the smart meters can be used as inputs for the control actions of the OLTC transformer.

This report provides an analysis on the benefits of a transformer with on load tap chang-ers on each phase that can be applied in the distribution system to accommodate more renewable generations such as photovoltaic power. The main purpose of this research is to verify whether power distribution transformer with OLTC per phase is necessary and valuable. The main conclusion is that power distribution transformer with OLTC control on each phase can significantly improve the PV hosting capacity in the analyzed unbal-anced scenarios. To investigate the verification problem, a simulation study is performed using the soft-wares DigSilent PowerFactory and Matlab. In this simulation study, a real low voltage network from Dong Eldistribution is modeled in Powerfactory. The measured data of the real low voltage network is analyzed and the resulting loading profiles including active and reactive power are used as load basics for the analysis. In term of PV genera-tion profiles, a realistic PV output power is assumed. Four relevant indicies such as phase neutral voltage, netural potential voltage, unbalanced factor (VUF), and power losses are evaluated in the present study. The simulation tests include two network layouts, considering a base case (passive net-work) and an active layout considering the PV integration. For each case, we compared the results of three scenarios firstly operating the network without OLTC transformer, then enabling the OLTC synchronously on three phases and finally with the OLTC act-ing independently on each phase. The simulations show that in the PV case the system hosting capacity reaches up to 105 kW for a very unbalance PV phase connection sce-nario (50% of the PV is connected on phase a and 50% of the PV is connected on phase b) and 210 kW for a less unbalanced PV phase connection (50% of the PV is connected on phase a, 30% of the PV is connected on phase b and 20% of the PV is connected on phase c), with the regulation of three single phase OLTC.

The core of this activity is to provide distribution system operators with tools for the optimal and grid-aware operation of utility-scale distributed battery energy storage systems (BESSs) in order to optimize the integration of stochastic distributed generation. The ultimate goal is the optimal control of active distribution networks with high penetration of stochastic (i.e., non-controllable) renewable-based generation. In particular, unscheduled fluctuations of the power exchanged with the upper grid level are minimised via the proposed control and scheduling framework, where we compute a dispatch plan in day-ahead using advanced forecasts of the aggregated prosumption and track it during the real-time operation using a grid-aware optimal power flow (OPF)-based control of the controllable BESS accounting for both grid constraints and BESS operational constraints. We experimentally validated the proposed control and scheduling strategy to dispatch the operation of a medium voltage active distribution network interfacing stochastic heterogeneous prosumers by using a grid-connected BESS as a controllable element coupled with a distributed monitoring infrastructure. In particular, the framework consists of two algorithmic layers. In the first one (day-ahead scheduling), an aggregated dispatch plan is determined, which is based on the day-ahead forecast of the prosumption and accounts for the operational constraints of grid and BESS state-of-energy. An adaptive data-driven scheme based on multi-variate Gaussian distribution is used to forecast the power consumption and photovoltaic generation and used as an input at the day-ahead stage. Then, the dispatch plan for the next 24 hours is computed using a scenariobased iterative AC OPF (Codistflow) algorithm, which accounts for forecasts of RESs and load profiles with 95% confidence interval with 1h time resolution. The second layer consists of real-time operation, where a grid-aware model predictive control determines the active and reactive power set-points of the BESS so that their aggregated contribution tracks the dispatch plan while obeying to BESS’s operational constraints as well as the grid’s ones. The grid constraints are modelled using the Augmented Relaxed OPF developed at the EPFL-DESL. The proposed control framework is validated by dispatching the operation of a 12kV/20MVA MV distribution network in Aigle, Switzerland (i.e. the REeL demonstrator) using a 1.5 MW/2.5 MWh BESS, which is controlled in real-time given the online grid state estimation enabled by the deployed distributed PMU-based sensing infrastructure.

1. Description of deliverable and goal 1.1. Executive summary The core of this activity is to provide distribution system operators with tools for the operation of utility-scale distributed battery energy storage systems (BESSs) in order to optimize the integration of stochastic distributed generation. The main goal of this deliverable is to assess two possible strategies for the real-time control of a utility-scale BESS to follow a day-ahead computed dispatch plan. In particular, one solution is based on a grid-aware optimal power flow (OPF)-based control accounting for both grid and BESS operational constraints (thoroughly described in D1.4.4c) [1], whereas the second one is based on the COMMELEC (thoroughly described in D1.2.3c) [2], [3]. The goal of the first method is to achieve the real-time dispatch plan tracking using a grid-aware model predictive control (MPC) to determine the active and reactive power set-points of the BESS so that the aggregated power of all the resources connected to a medium voltage power grid contribution track the dispatch plan while obeying to BESS’s operational constraints as well as the grid’s ones. The grid constraints are modelled using the Augmented Relaxed OPF [4]. COMMELEC is a framework proposed in the literature ([2], [3]) for the real-time control of power grids. It uses a hierarchy of agents to compute explicit active and reactive power setpoints for the resources connected to the grid. Each resource is equipped with a resource agent (RA) whose job is to translate the internal state of the resource into a device-independent format (advertisement). The advertisements are collected by the grid agent (GA), which computes the optimal power setpoints that optimize a global objective. The global objective is the weighted sum of various objectives, including tracking a predetermined dispatch plan at the slack bus, minimizing grid’s nodal voltage deviations from the nominal value, limiting the line currents below the respective ampacities and achieving target internal states for the resources. The proposed control frameworks are validated by dispatching the operation of a 12kV/20MVA MV distribution network in Aigle, Switzerland (i.e. the REeL demonstrator) using a 1.5 MW/2.5 MWh BESS, which is controlled in real-time given the online grid state estimation enabled by the deployed distributed PMU-based sensing infrastructure.

Given a renewable power supply, the replacement of conventional vehicles with electric alternatives has the potential to significantly reduce climate gas emissions from the transport sector. Norway has implemented economic incentives over several years to encourage a transition from conventional vehicles to electric cars (EVs), and has now the largest share of EVs per capita in the world. The power levels required to charge this fleet may constitute a significant strain on the existing power grid, especially at a low voltage level. The deployment of fast chargers may further aggravate this. More knowledge about the challenges ahead will be advantageous. This thesis explores the effects of increasing EV penetration levels in a Norwegian distribution grid, by analyzing real power measurements obtained from household smart meters. The implications of installing a fast charger in the grid has been assessed, an optimal location for it has been proposed, and the potential for reactive power injection to reduce the voltage deviations caused by it has been investigated. After presenting the theoretical groundwork, data set and methodology, the model is presented in detail and the following results are described. Results show that the EV hosting capacity of the grid is good for a majority of the end-users, but that the weakest power cable would be overloaded at a 20 % EV penetration level. The network tolerated an EV penetration of 50 % with regards to the voltage levels at all end-users. Injecting reactive power at the location of an installed fast charger proved to significantly reduce the voltage deviation otherwise imposed by the charger.