Publications

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This quick note outlines what we found after our conversion with you and your team. As suggested, we loaded 1547-2003 source requirements document (SRD) and then went back and loaded 1547-2018 SRD. This did result in implementing the new 1547-2018 settings. This short report focuses on the frequency-watt function and shows a couple of screen shots of the parameter settings via the Mojave HMI interface and plots of the results of the inverter with FW function enabled in both default and most aggressive settings response to frequency events. The first screen shot shows the 1547-2018 selected after selecting 1547-2003.

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The proper coordination of power system protective devices is essential for maintaining grid safety and reliability but requires precise knowledge of fault current contributions from generators like solar photovoltaic (PV) systems. PV inverter fault response is known to change with atmospheric conditions, grid conditions, and inverter control settings, but this time-varying behavior may not be fully captured by conventional static fault studies that are used to evaluate protection constraints in PV hosting capacity analyses. To address this knowledge gap, hosting capacity protection constraints were evaluated on a simplified test circuit using both a time-series fault analysis and a conventional static fault study approach. A PV fault contribution model was developed and utilized in the test circuit after being validated by hardware experiments under various irradiances, fault voltages, and advanced inverter control settings. While the results were comparable for certain protection constraints, the time-series fault study identified additional impacts that would not have been captured with the conventional static approach. Overall, while conducting full time-series fault studies may become prohibitively burdensome, these findings indicate that existing fault study practices may be improved by including additional test scenarios to better capture the time-varying impacts of PV on hosting capacity protection constraints.

Inverters convert DC power to AC power that can be injected into the grid. Many inverters offer multiple, independent maximum power point trackers (MPPTs) to accommodate photovoltaic arrays with different orientations or capacities. No validated model for overall DC-to-AC power conversion efficiency is available for such inverters. Herein, we propose a mathematical model that describes the efficiency of a multi-MPPT inverter and present validation using a commercial inverter with six MPPT inputs.

With the increase in penetration of inverter-based resources (IBRs) in the electrical power system, the ability of these devices to provide grid support to the system has become a necessity. With standards previously developed for the interconnection requirements of grid-following inverters (GFLI) (most commonly photovoltaic inverters), it has been well documented how these inverters 'should' respond to changes in voltage and frequency. However, with other IBRs such as grid-forming inverters (GFMIs) (used for energy storage systems, standalone systems, and as uninterruptable power supplies) these requirements are either: not yet documented, or require a more in deep analysis. With the increased interest in microgrids, GFMIs that can be paralleled onto a distribution system have become desired. With the proper control schemes, a GFMI can help maintain grid stability through fast response compared to rotating machines. This paper will present an experimental comparison of commercially available GFMIand GFLI ' responses to voltage and frequency deviation, as well as the GFMIoperating as a standalone system and subjected to various changes in loads.

For the resiliency of both small and large distribution systems, the concept of microgrids is arising. The ability for sections of the distribution system to be 'self-sufficient' and operate under their own energy generation is a desirable concept. This would allow for only small sections of the system to be without power after being affected by abnormal events such as a fault or a natural disaster, and allow for a greater number of consumers to go through their lives as normal. Research is needed to determine how different forms of generation will perform in a microgrid, as well as how to properly protect an islanded system. While synchronous generators are well understood and generally accepted amongst utility operators, inverter-based resources (IBRs) are less common. An IBR's fault characteristic varies between manufacturers and is heavily based on the internal control scheme. Additionally, with the internal protections of these devices to not damage the switching components, IBRs are usually limited to only 1.1-2.5p.u. of the rated current, depending on the technology. This results in traditional protection methods such as overcurrent devices being unable to 'trip' in a microgrid with high IBR penetration. Moreover, grid-following inverters (commonly used for photovoltaic systems) require a voltage source to synchronize with before operating. Also, these inverters do not provide any inertia to a system. On the other hand, grid-forming inverters can operate as a primary voltage source, and provide an 'emulated inertia' to the system. This study will look at a small islanded system with a grid-forming inverter, and a grid-following inverter subjected to a line-to-ground fault.

The proper coordination of power system protective devices is essential for maintaining grid safety and reliability but requires precise knowledge of fault current contributions from generators like solar photovoltaic (PV) systems. PV inverter fault response is known to change with atmospheric conditions, grid conditions, and inverter control settings, but this time-varying behavior may not be fully captured by conventional static fault studies that are used to evaluate protection constraints in PV hosting capacity analyses. To address this knowledge gap, hosting capacity protection constraints were evaluated on a simplified test circuit using both a time-series fault analysis and a conventional static fault study approach. A PV fault contribution model was developed and utilized in the test circuit after being validated by hardware experiments under various irradiances, fault voltages, and advanced inverter control settings. While the results were comparable for certain protection constraints, the time-series fault study identified additional impacts that would not have been captured with the conventional static approach. Overall, while conducting full time-series fault studies may become prohibitively burdensome, these findings indicate that existing fault study practices may be improved by including additional test scenarios to better capture the time-varying impacts of PV on hosting capacity protection constraints.

Renewable energy has become a viable solution for reducing the harmful effects that fossil fuels have on our environment, prompting utilities to replace traditional synchronous generators (SG) with more inverter-based devices that can provide clean energy. One of the biggest challenges utilities are facing is that by replacing SG, there is a reduction in the systems' mechanical inertia, making them vulnerable to frequency instability. Grid-forming inverters (GFMI) have the ability to create and regulate their own voltage reference in a manner that helps stabilize system frequency. As an emerging technology, there is a need for understanding their dynamic behavior when subjected to abrupt changes. This paper evaluates the performance of a GFMI when subjected to voltage phase jump conditions. Experimental results are presented for the GFMI subjected to both balanced and unbalanced voltage phase jump events in both P/Q and V/f modes.

Grid support functionalities from advanced PV inverters are increasingly being utilized to help regulate grid conditions and enable high PV penetration levels. To ensure a high degree of reliability, it is paramount that protective devices respond properly to a variety of fault conditions. However, while the fault response of PV inverters operating at unity power factor has been well documented, less work has been done to characterize the fault contributions and impacts of advanced inverters with grid support enabled under conditions like voltage sags and phase angle jumps. To address this knowledge gap, this paper presents experimental results of a three-phase photovoltaic inverter's response during and after a fault to investigate how PV systems behave under fault conditions when operating with and without a grid support functionality (autonomous Volt-Var) enabled. Simulations were then conducted to quantify the potential impact of the experimental findings on protection systems. It was observed that fault current magnitudes across several protective devices were impacted by non-unity power factor operating conditions, suggesting that protection settings may need to be studied and updated whenever grid support functions are enabled or modified.

In order to address the recent inclement weather-related energy events, electricity production is experiencing an important transition from conventional fossil fuel based resources to the use of Distributed Energy Resources (DER), providing clean and renewable energy. These DERs make use of power electronic based devices that perform the energy conversion process required to interface with the utility grids. For the particular cases where DC/AC conversion is required, grid-forming inverters (GFMI) are gaining popularity over their grid-following (GFLI) counterpart. This is due to the fact that GFMI do not require a dedicated Phase Locked Loop (PLL) to synchronize with the grid. The absence of a PLL allows GFMI to operate in stand-alone (off-grid) mode when needed. Nowadays, inverter manufacturers are already offering several products with grid-forming capabilities. However, modeling the dynamics of commercially available GFMI under heavy loads or faults scenarios has become a critical task not only for stability studies, but also for coordination and protection schemes in power grids (or microgrids) that are experiencing a steady growth in their levels of DERs. Based upon experimental low-impedance fault results performed on a commercially available GFMI, this paper presents a modeling effort to replicate the dynamics of such inverters under these abnormal scenarios. The proposed modeling approach relies on modifying previously developed GFMI models, by adding the proper dynamics, to match the current and voltage transient behavior under low-impedance fault scenarios. For the first inverter tested, a modified CERTS GFMI model provides matching transient dynamics under faults scenarios with respect to the experimental results from the commercially available inverter.

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By strategically curtailing active power and providing reactive power support, photovoltaic (PV) systems with advanced inverters can mitigate voltage and thermal violations in distribution networks. Quasi-static time-series (QSTS) simulations are increasingly being utilized to study the implementation of these inverter functions as alternatives to traditional circuit upgrades. However, QSTS analyses can yield significantly different results based on the availability and resolution of input data and other modeling considerations. In this paper, we quantified the uncertainty of QSTS-based curtailment evaluations for two different grid-support functions (autonomous Volt-Var and centralized PV curtailment for preventing reverse power conditions) through extensive sensitivity analyses and hardware testing. We found that Volt-Var curtailment evaluations were most sensitive to poor inverter convergence (-56.4%), PV time-series data (-18.4% to +16.5%), QSTS resolution (-15.7%), and inverter modeling uncertainty (+14.7%), while the centralized control case was most sensitive to load modeling (-26.5% to +21.4%) and PV time-series data (-6.0% to +12.4%). These findings provide valuable insights for improving the reliability and accuracy of QSTS analyses for evaluating curtailment and other PV impact studies.

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With inverter-based distributed energy resources (DERs) becoming more prevalent in grid-connected or islanded distribution feeders, a better understanding of the performance of these devices is needed. Increasing the amount of inverter-based generation, and therefore reducing conventional generation, i.e. rotating machines and synchronous generators, decreases generation sources with well-known characteristic responses for unbalanced and transient fault conditions. This paper experimentally tests the performance of commercial grid-forming inverters under fault and unbalanced conditions and provides a comparison between grid-forming inverters and their grid-following counterparts.

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During the last decade, utility companies around the world have experienced a significant increase in the occurrences of either planned or unplanned blackouts, and microgrids have emerged as a viable solution to improve grid resiliency and robustness. Recently, power converters with grid-forming capabilities have attracted interest from researchers and utilities as keystone devices enabling modern microgrid architectures. Therefore, proper and thorough testing of Grid-Forming Inverters (GFMIs) is crucial to understand their dynamics and limitations before they are deployed. The use of closed-loop real-time Power Hardware-in-the-Loop (PHIL) simulations will facilitate the testing of GFMIs using a digital twin of the power system under various contingency scenarios within a controlled environment. So far, lower to medium scale commercially available GFMIs are difficult to interface into PHIL simulations because of their lack of a synchronization mechanism that allows a smooth and stable interconnection with a voltage source such as a power amplifier. Under this scenario, the use of the well-known Ideal Transformer Method to create a PHIL setup can lead to catastrophic damages of the GFMI. This paper addresses a simple but novel method to interface commercially available GFMIs into a PHIL testbed. Experimental results showed that the proposed method is stable and accurate under standalone operation with abrupt (step) load-changing dynamics, followed by the corresponding steady state behavior. Such results were validated against the dynamics of the GFMI connected to a linear load bank.

During the last decade, utility companies around the world have experienced a significant increase in the occurrences of either planned or unplanned blackouts, and microgrids have emerged as a viable solution to improve grid resiliency and robustness. Recently, power converters with grid-forming capabilities have attracted interest from researchers and utilities as keystone devices enabling modern microgrid architectures. Therefore, proper and thorough testing of Grid-Forming Inverters (GFMIs) is crucial to understand their dynamics and limitations before they are deployed. The use of closed-loop real-time Power Hardware-in-the-Loop (PHIL) simulations will facilitate the testing of GFMIs using a digital twin of the power system under various contingency scenarios within a controlled environment. So far, lower to medium scale commercially available GFMIs are difficult to interface into PHIL simulations because of their lack of a synchronization mechanism that allows a smooth and stable interconnection with a voltage source such as a power amplifier. Under this scenario, the use of the well-known Ideal Transformer Method to create a PHIL setup can lead to catastrophic damages of the GFMI. This paper addresses a simple but novel method to interface commercially available GFMIs into a PHIL testbed. Experimental results showed that the proposed method is stable and accurate under standalone operation with abrupt (step) load-changing dynamics, followed by the corresponding steady state behavior. Such results were validated against the dynamics of the GFMI connected to a linear load bank.

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