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Distribution grid with high solar penetration can cause huge voltage fluctuations due to sudden change of solar generation. This causes power quality issues, customer dissatisfaction and risks customer equipment. As a result, voltage control becomes extremely important since utilities have to keep the service voltage between 114V and 126V. Conventional electromechanical voltage control devices like Load Tap Changers (LTCs) and Switched Capacitor Banks (SCBs) do not act fast enough to mitigate the voltage fluctuations cause by solar. New methods are being suggested to use smart inverters going forward, but most inverters are still legacy inverters in the field. This paper introduces a novel approach by using Dynamic V Ar Controllers (DVC) to regulate the voltage by injecting reactive power dynamically. A pilot project at Hawaiian Electric has shown that with 30 DVCs distributed on a feeder with 37% (1.03 MW PV ) PV penetration, DVCs reduce feeder voltage fluctuations up to 1.54%(1.85V) which could increase the PV hosting capacity of the circuit from 37% (1.03 MW PV ) to 99% (2.7 MW PV ).

With high penetration of solar Photovoltaic (PV) resources, controlling voltage of distribution systems with conventional control strategies such as fixed set-point operation mode of Load Tap Changers (LTCs) or even in some cases with Line-Drop Compensation (LDC) operation mode is not possible anymore. In case of LDC operation mode, optimizing the R & X settings is time-consuming and is required with every change in PV penetration level. Hence, a robust and dynamic control strategy is required to handle the challenges induced by high penetration levels of solar PV resources. In this work, dynamic control of LTC and Line Voltage Regulators (LVRs) of a Hawaii substation with multiple voltage control zones is implemented in OpenDSS and controlled by Python through COM interface. Then its performance in terms of reducing voltage volatility, Operation and Maintenance (O&M) costs and ramp-rate, facilitating LDC R&X settings optimization and energy saving is evaluated. Furthermore, the impact of Dynamic Var Controllers (DVCs) in accomplishing the aforementioned objectives is illustrated through comprehensive time-series simulations. Simulation results show that by using dynamic control of voltage regulators and DVCs, PV penetration increases by 45% due to reducing voltage volatility. Moreover, generation ramp-rate reduces by 8%. Furthermore, energy savings are tripled compared to energy savings achieved by existing controls. Finally, the utilization of DVCs reduces the O&M costs by 14%.

Adoption of renewable energies is on the rise all over the globe. Among renewable energy resources, solar Photovoltaic (PV) resources have gained a significant momentum in multiple parts of the world. Beside all the benefits renewable energy resources provide, they have also introduced new challenges, which must be addressed as soon as possible. This paper focuses on the mitigation of voltage issues caused by high penetration of PV resources. In this work, new Volt- V Ar Control (VVC) devices such as smart inverters and Dynamic VAr Controllers (DVCs) are selected and the interplay between them is investigated. Furthermore, the impact of these new VVC technologies on reducing voltage volatility and consequently increasing PV hosting capacity of distribution systems is assessed. To achieve those objectives, advanced Quasi-Static Time-Series (QSTS) simulations are performed in OpenDSS and controlled by Python. These powerful tools provide the opportunity to model new VVC devices, to implement advanced VVC schemes and smart functions, and to investigate the interaction between new VVC devices. Simulation results for select feeders show that by employing smart inverters and DVCs, existing PV hosting capacity of the considered Hawaiian distribution system can increase by 15% and 45% respectively compared to existing installed capacity. However, when both technologies are utilized, PV hosting increases by 60% for the select feeders, indicating that DVCs complement smart inverters capabilities.

This paper presents a modeling framework for realworld distribution systems to enable large-scale transmission-and-distribution (T&D) cosimulation. The modeling methodology includes three major steps: utility feeder model conversion, feeder load modeling, and model validation. The feeder models obtained from the utility are converted to the format that is more flexible for analysis and algorithm development. The load profile of each medium-voltage bus is modeled based on the data obtained from advanced metering infrastructure and the supervisory control and data acquisition (SCADA) system. Then the converted feeder models are validated by comparing the simulated feeder-head voltage results to the measured voltage data from SCADA. Last, the modeled real-world large-scale distribution systems are integrated into a T&D cosimulation framework to perform the system simulation from the bulk system down to the medium-voltage buses in the distribution system.

Driving through many neighborhoods of Hawai'i, it is hard to miss the nearly ubiquitous rooftop solar photovoltaic (PV) systems that have popped up during the past eight years or so. Relatively high electricity costs associated with island grids, coupled with various incentives, have made it cost-effective to install solar over the last eight years, as evidenced by the PV-deployment chart in Figure 1. On the most populous island, O'ahu, the PV nameplate acgenerating capacity of 502 MW totals nearly half of the annual peak load for the entire island, which is 1.1 GW . Of that 502 MW of PVs, 54% is from private rooftop solar-nearly 50,000 residences or roughly one of every three single family homes. But Hawaiian Electric, the local utility, has no way to monitor or control the PV generation, even for most nonresidential systems. This means that on sunny days, up to approximately half of the PV generation is outside of the utility's control. This poses many challenges for utility planners and operators-challenges that Hawaiian Electric has been working diligently to address, along with various partners, notably the U.S. Department of Energy (DOE), the National Renewable Energy Laboratory (NREL), and its Energy System's Integration Facility (ESIF). This article describes how Hawaiian Electric has worked with engineers in NREL's Power Systems Engineering Center to improve the way its grid operates with very high levels of distributed PVs, largely by changing the way the PV inverters are operated.

Adoption of solar Photovoltaic (PV) is on the rise in different parts of the world. Till date, most solutions proposed to mitigate voltage problems caused by high PV penetration on distribution network have hovered around smart inverters. As new control technologies at the grid-edge such as Secondary VAr Controllers (SVCs) become ubiquitous, the need to understand the interplay between smart inverters and SVCs is felt. This paper addresses the interaction between smart inverters and SVCs through QSTS simulations. The field results collected from a pilot project performed at Hawaiian electric are taken as the basis for conducting these simulations and creating future scenarios. Using SVCs, Smart Inverters and optimized settings of the LTC, it is demonstrated that the PV hosting capacity of the distribution system can be doubled from (4.8MW PV to 9.6 MW PV ) without causing voltage problems. Further, using a dynamic coordinated control of the LTC with SVCs, it is shown that the ramp rate of real power flow at the substation during evening time (duck curve effect) can be reduced by 10.8%. Finally, it is conjectured that the dynamic control of LTC can eliminate the need for extensive DER interconnection studies by naturally achieving optimized settings under varying operating conditions.

High residential PV penetration in the distribution grid can cause large voltage variations due to sudden changes in PV generation. This ultimately degrades power quality, customer satisfaction, risks utility infrastructure, customer equipment and utility employees working in the field. As a result, controlling voltage becomes imperative given that most utilities have to maintain voltage within a service range of 114V to 126V. Conventional assets, such as LTCs and Cap Banks, do not respond fast enough to mitigate these voltage variations. Lack of fast distributed control limits further PV penetration. Newer approaches of using smart inverters moving forward are being proposed, however, most inverters in the field are still legacy inverters. This paper presents a novel approach of using Secondary VAr Controllers (SVC) to control voltage by injecting VArs dynamically. Through a pilot project on a system with 77% (4.8 MW PV ) PV penetration at Hawaiian Electric, it is demonstrated that 61 SVCs distributed on two feeders can tighten the feeder-wide voltage profile by up to 4% (4.8V), which translates to nearly doubling (146% or 9.23 MW PV ) of the PV hosting capacity.

As advanced grid-support functions (AGF) become more widely used in grid-connected photovoltaic (PV) inverters, utilities are increasingly interested in their impacts when implemented in the field. These effects can be understood by modeling feeders in real-time simulators and test PV inverters using power hardware-in-the-loop (PHIL) techniques. This paper presents a novel feeder model reduction algorithm using a ruin & reconstruct methodology that enables large feeders to be solved and operated on real-time computing platforms. Two Hawaiian Electric feeder models in Synergi Electric's load flow software were converted to reduced order models in OpenDSS, and subsequently implemented in the OPAL-RT real-time digital testing platform. Smart PV inverters were added to the realtime model with AGF responses modeled after characterizing commercially available hardware inverters. Finally, hardware inverters were tested in conjunction with the real-time model using PHIL techniques so that the effects of AGFs on the feeders could be analyzed.