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In recent years, the voltage fluctuation in distribution grids has become a more serious problem due to a large amount of residential PV penetration. The authors have so far studied the ideal low-voltage grid configuration that can accept large number of PV connections. Although the problem has been formulated and the solution method has been proposed, a more efficient solution method is necessarily desired since the problem is a planning problem. In this paper, to obtain the ideal grid configuration more efficiently, the authors propose a new framework by utilizing Interval Arithmetic (IA), in which the formulation and the solution method are also renewed. In the proposed framework, the uncertainties of PV output and load fluctuations are expressed with interval variables, and the grid configuration is efficiently derived by utilizing IA. To verify the effectiveness, the proposed framework is tested through several numerical simulations with successful results.

In this paper, we propose a comprehensive scheme to determine a suitable method and timing for upgrading the voltage control method. Voltage control methods are expected to be upgraded in accordance with the photovoltaic (PV) penetration in distribution systems. The suitable method and timing detailed in this paper are based on the limit of the PV penetration rate, which is constrained by the regulated voltage deviation. The upgrade process involves moving the on-load tap changer (OLTC) control method from the conventional scalar line drop compensator (LDC) method to the vector LDC method or centralized control method. Then, a static var compensator (SVC) or step voltage regulator (SVR) is installed. The locations of the SVR and SVC are determined to maximize the PV penetration rate. The suitable method and timing are demonstrated using a general distribution system. In addition to the numerical simulations, experiments are performed using an active network system with energy resources. The experimental results are consistent with the numerical simulation results, thus validating the proposed scheme. The maximum PV penetration rate obtained using the OLTC control method is 55%. Whereas, the installation of the SVR and SVC increased the rate to 95% and 100%, respectively.

Voltage ride-through (VRT) and dynamic voltage support (DVS) are advanced functions of photovoltaic (PV) systems that are expected to improve future power system stability. Toward the improvement in system stability, it is valuable for power system operators (PSOs) to evaluate the effects of these functions. However, it is not straightforward to evaluate the amount of volt-ampere reactive (var) injection from PV systems because var injection depends on weather conditions and on the terminal voltages of the PV systems during voltage sag. In addition, it is equally important to analyze var support from distribution systems (DSs) to accurately determine the amount of var injection in a power system since numerous PV systems are connected to DSs. In this study, we evaluate the var support at a substation of a DS with PV during a voltage sag under various weather conditions. The var injection was analyzed for several time zones and seasons to consider a change in solar radiation. A numerical simulation was conducted based on IEEE 13 Node Test Feeder Model with PV systems. The results indicated that there is a large variation in var support depending on seasons or time zones with different solar irradiance.

Battery energy storage systems (BESSs) have attracted much attention as a key device for realizing the installation of photovoltaic plants (PVPs) in distribution networks. To improve the cost-effectiveness of BESSs, multipurpose utilization is required. In addition, the BESSs in a distribution network are generally used over a decade or more, and the role and size of BESSs may change according to the distribution network’s condition, such as the PVP penetration level. Consequently, an ad hoc BESS installation may increase excess BESS capacity, which is detrimental to cost-effectiveness. Therefore, a multipurpose utilization and planning method is desired for BESSs. This paper proposes a multipurpose control and planning (MCP) method for BESSs to cope with the increase of large-scale PVPs in distribution networks. The proposed method executes power smoothing, reverse-power-flow (RPF) prevention, and state-of-charge (SoC) adjustment without interactions between controls, and it determines a suitable BESS site and type based on three indices: (1) BESS capacity, (2) the number of tap operations of an on-load tap changer (OLTC) and a step voltage regulator (SVR), and (3) PVP curtailment. The BESS is used for power smoothing of a substation/PVPs and RPF prevention at the substation. To evaluate the impact of the BESS installation on tap operation and PVP curtailment, the voltage regulation methods of OLTC, SVR, and PVP inverters were implemented. According to the results, the substation was selected as a suitable BESS site regardless of the number of PVPs and BESS type. Furthermore, lithium-ion battery (LiB) was the preferred BESS type when PVP penetration rate (PR) was less than 67%, and redox flow battery (RFB) was selected as the BESS type when the PR was 100%. The simulation results indicate that the MCP method can achieve multipurpose control and determine the suitable BESS site and type.

In this study, we evaluate the Volt- VArand Volt-V AR-Watt functions of smart inverters based on the PV penetration level (PVPL) and the photovoltaic (PV) curtailment. The Volt- VArand Volt- V Ar- Watt functions are compared with the optimal control parameters that maintain the distributed network voltage within an admissible range and minimize PV curtailment. The study results at each PVPL (0-100%) with a typical distribution network model highlight the following points within our conditions. (1) Optimal control parameters vary with the PVPL and two weather conditions; (2) The maximum PVPL does not reach 100% with the Volt-V Arfunction, whereas the Volt-VAR-Watt function enables the maximum PVPL to reach 100%; and (3) the Volt-VAR-Watt function curtails PV generation, and the average ratio of PV curtailment on cloudy and sunny days is about 12.1 % and 0.16%, respectively.

As the number of distributed energy resources (DERs) continues to increase, the DER response during a fault is becoming critical to power system stability. In the near future, DERs are expected to provide advanced functions such as voltage ride through and dynamic voltage support to maintain stable power system operation. In this context, an aggregated model of dynamic DERs that includes these advanced functions has been developed previously under the composite load model structure. In order to provide model parameters appropriate for an actual distribution system, however, dynamic simulations based on a detailed feeder model are required. Therefore, the purpose of this study is to evaluate the dynamic voltage response of a detailed feeder model incorporating modern DERs. In experiments on data from an actual circuit in California, the dynamic simulations reveal the partial loss behaviors of the DERs for several voltage sags, along with reactive current output induced by the dynamic voltage support.

Smart inverter functions, like Volt-VAR control, can improve the integration of photovoltaic systems in a distribution feeder. A challenge in grid planning and operation is the identification of optimal Volt-VAR settings in combination with existing voltage regulation schemes applied by the utility. This paper features a technical assessment of smart inverter Volt-VAR settings in combination with an advanced load tap changer control. Quasi-Static Time Series (QSTS) simulation using the IEEE 13 node test feeder and different distributed PV penetration scenarios is carried out. The results show a clear trend for optimal Volt-VAR settings for the different PV penetration scenarios.

This paper introduces a process for determining the site, size, and control parameters for a large-scale battery system (LSBS) with Volt-VAR function in a distribution network with advanced load tap changer (LTC) control. The net impact of the LSBS is evaluated based on four constraints: 1) voltage violations, 2) LTC tap operations, 3) network losses, and 4) power factor at the feeder head. In addition, the power quality (based on the voltages on any node across the feeder) with and without the LSBS are compared. Quasi-Static Time Series (QSTS) simulation with an IEEE 13 node test feeder and four PV penetration scenarios is conducted. The study results highlight the most suitable size and site of the LSBS for the given conditions.

This paper proposes a method to determine the combined energy (kWh) and power (kW) capacity of a battery energy storage system and power conditioning system capacity (kVA) based on load leveling and voltage control performances. Through power flow calculations, a relationship between the capacity combination and the control performance is identified and evaluated. A tradeoff relationship between the capacity combination and control performance is confirmed, and the proper capacity combination for operation is determined based on the evaluated relationship. In addition, the control performance of the capacity combination is evaluated through the power flow calculation, confirming that the proposed method is effective for determining the optimized capacity combination.

In this study, updating parameters of smart inverters (SI) based on the change of PV penetration rate and weather conditions was evaluated. Among a wide variety of functionalities of SI, we focused on Volt-VAR control and comprehensively investigated the voltage profile in distribution network (DN) for various parameters. For the scenario in which PV penetration rate or weather condition was changed, we compared the total energy loss for the updated and fixed parameters, while avoiding voltage violation. We found that the maximum reduction rate of energy loss by appropriately changing the Volt-VAR parameters was 14.4% and 13.7%, respectively for the two cases, and that the parameters should be preferably updated according to the condition of DN from the view point of reducing energy loss. Quantitative results of Volt-VAR parameters survey were summarized, which can be a guide for how to use the functionality when PV is heavily installed in DN.

In this study, we determine the suitable method and timing for the renewal of the voltage control method using voltage control performance evaluated by the maximum photovoltaic (PV) installation rate possible without voltage deviation. The voltage control method is renewed when the voltage of a distribution system deviates with an existing voltage control method. We determine the most suitable voltage control method, which extends the most PV systems, and define its renewal timing as the moment when the PV installation causes voltage deviation. For the renewal of the voltage control method, changing the control operation of a load ratio control transformer (LRT) and the additional installation of a static VAR compensator (SVC) are considered. A numerical simulation is performed to calculate the limit of PV installation rate of each voltage control method to determine the suitable one and its renewal timing.