Jimmy Edward Quiroz

Time series simulation of voltage regulation device control modes

The integration of photovoltaic systems (PV) on distribution feeders may result in unfavorable increases in the number of operations of voltage regulation devices, or may decrease the effectiveness of their settings, resulting in the need for mitigation. Voltage regulation devices commonly use controllers that have time delay settings and sample power system parameters at a high frequency. Quasi-static time series (QSTS) power flow simulation is necessary to properly analyze the impact of distributed PV integration on voltage regulation device operations. It is possible to properly simulate complex control algorithms through a COM interface program, resulting in more realistic and valuable results.

Detailed grid integration analysis of distributed PV

This paper shows examples of detailed PV grid integration analysis performed by Sandia National Laboratories (SNL) on two separate distribution feeders with two different simulated PV deployments for each. Through the use of advanced modeling tools and techniques, examples of time-series detailed feeder modeling are presented. Feeders in Utah and Georgia with simulated 100% PV penetration, either central or distributed, were studied. The analysis approach of each deployment type and location on the feeder is described, as well as the use of advanced PV output estimations for modeling maximum solar variability. Comparisons of the performance measured for each feeder, including maximum steady-state voltage and voltage regulation equipment operations, are shown. Impact results from the analyses are described, as well as any potential mitigations. Future analysis aspects are discussed in relation to the detailed study findings thus far.

Initial operating experience of the 1.2-MW La Ola photovoltaic system

The 1.2-MW La Ola photovoltaic (PV) power plant in Lanai, Hawaii, has been in operation since December 2009. The host system is a small island microgrid with peak load of 5 MW. Simulations conducted as part of the interconnection study concluded that unmitigated PV output ramps had the potential to negatively affect system frequency. Based on that study, the PV system was initially allowed to operate with output limited to 50% of nameplate power capacity to reduce the potential for frequency instability due to PV variability. Based on the analysis of historical voltage, frequency, and power output data at 50% output level, the PV system has not significantly affected grid performance. However, it should be noted that the impact of PV variability on active and reactive power output of the nearby diesel generators was not evaluated.

PV interconnection risk analysis through distribution system impact signatures and feeder zones

High penetrations of PV on the distribution system can impact the operation of the grid and may require interconnection studies to prevent reliability problems. In order to improve the interconnection study process, the use of feeder zones and PV impact signatures are proposed to group feeders by allowable PV size as well as by their limiting factors for the interconnection. The feeder signature separates feeders into different impact regions with varying levels of PV interconnection risk, accounting for impact mitigation strategies and associated costs. This locational information improves the speed and accuracy of the interconnection screening process. The interconnection risk analysis methodology is based on the feeder and interconnection parameters such as: feeder type, feeder characteristics, and location and size of PV. PV impact signatures, hosting capacity, and feeder risk zones are demonstrated for four realistic distribution systems.

Small signal stability of the western North American power grid with high penetrations of renewable generation

The goal of this effort was to assess the effect of high penetration solar deployment on the small signal stability of the western North American power system (wNAPS). Small signal stability is concerned with the system response to small disturbances, where the system is operating in a linear region. The study area consisted of the region governed by the Western Electricity Coordinating Council (WECC). General Electrics Positive Sequence Load Flow software (PSLF®) was employed to simulate the power system. A resistive brake insertion was employed to stimulate the system. The data was then analyzed in MATLAB1® using subspace methods (Eigensystem Realization Algorithm). Two different WECC base cases were analyzed: 2022 light spring and 2016 heavy summer. Each base case was also modified to increase the percentage of wind and solar. In order to keep power flows the same, the modified cases replaced conventional generation with renewable generation. The replacements were performed on a regional basis so that solar and wind were placed in suitable locations. The main finding was that increased renewable penetration increases the frequency of inter-area modes, with minimal impact on damping. The slight increase in mode frequency was consistent with the loss of inertia as conventional generation is replaced with wind and solar. Then, distributed control of renewable generation was assessed as a potential mitigation, along with an analysis of the impact of communications latency on the distributed control algorithms.

High temporal resolution load variability compared to PV variability

While solar variability has often been quantified and its impact to distribution grids simulated, load variability, especially high-frequency (e.g., 1-second) load variability, has been given less attention. The assumption has often been made that high-frequency load variability is much smaller than PV variability, but with little evidence. Here, we compare load and PV variability using 1-second measurements of each. The impact on voltage regulator tap change operations of using low-resolution (e.g., 15- or 30-minute) interpolated load profiles instead of 1- second is quantified. Our results generally support the assumption that distribution feeder aggregate PV variability is much greater than aggregate load variability.

PV ramp rate smoothing using energy storage to mitigate increased voltage regulator tapping

A control algorithm is designed to smooth the variability of PV power output using distributed batteries. The tradeoff between smoothing and battery size is shown. It is also demonstrated that large numbers of highly distributed current, voltage, and irradiance sensors can be utilized to control the distributed storage in a more optimal manner. It is also demonstrated that centralized energy storage control for PV ramp rate smoothing requires very fast communication, typically less than a 15-second update rate. Finally, advanced inverter dynamic reactive current is shown to provide voltage variability smoothing, hence reducing the number of voltage regulator tap changes without energy storage.

Methods to determine recommended feeder-wide advanced inverter settings for improving distribution system performance

This paper describes methods that a distribution engineer could use to determine advanced inverter settings to improve distribution system performance. These settings are for fixed power factor, volt-var, and volt-watt functionality. Depending on the level of detail that is desired, different methods are proposed to determine single settings applicable for all advanced inverters on a feeder or unique settings for each individual inverter. Seven distinctly different utility distribution feeders are analyzed to simulate the potential benefit in terms of hosting capacity, system losses, and reactive power attained with each method to determine the advanced inverter settings.

Evaluation of communication requirements for voltage regulation control with advanced inverters

A central control algorithm was developed to utilize photovoltaic system advanced inverter functions, specifically fixed power factor and constant reactive power, to provide distribution system voltage regulation and to mitigate voltage regulator tap operations by using voltage measurements at the regulator. As with any centralized control strategy, the capabilities of the control require a reliable and fast communication infrastructure. These communication requirements were evaluated by varying the interval at which the controller sends dispatch commands and evaluating the effectiveness to mitigate tap operations. The control strategy was demonstrated to perform well for communication intervals faster than the delay on the voltage regulator (30 seconds). The communication reliability, latency, and bandwidth requirements were also evaluated.

Alternatives to the 15% Rule

The third solicitation of the California Solar Initiative (CSI) Research, Development, Demonstration and Deployment (RD&D) Program established by the California Public Utility Commission (CPUC) is supporting the Electric Power Research Institute (EPRI), National Renewable Energy Laboratory (NREL), and Sandia National Laboratories (SNL) with collaboration from Pacific Gas and Electric (PG&E), Southern California Edison (SCE), and San