This paper reviews the current state of distributed energy resource (DER) commissioning practices from U.S. utilities, focusing on the implementation of IEEE 1547-2018 DER interconnection requirements. The paper also reviews the standard requirements for DER conformity assessment, describes typical utility interconnection processes, and summarizes existing commissioning practices. Key challenges and gaps in current practices are identified including EPRI’s perspective on needed improvements. The findings highlight the need for standardized approaches to DER commissioning and field testing as utilities continue to integrate increasing amounts of inverter-based resources into the power grid.

This paper presents effective grounding criteria for high penetration inverter-based resources (IBRs) in distribution networks. It demonstrates that traditional methods of employing supplemental grounding exclusively does not prevent excessive ground fault overvoltages (GFOV) where adoption levels of IBRs exceed a distribution feeder minimum load. Definitions and requirements are presented for quantifying and mitigating IBR-caused GFOV such that the distribution utility is protected. The requirements are tested using a real, albeit generic case study within the EMTP-RV environment to demonstrate their efficacy.

DER interconnection transformers, especially their winding configurations can affect various aspects of system operations and protection. Among others, the selection of winding configuration can affect a DER plant's response to faults and open phases including detection of events, coordination with other protection systems, levels of ground fault overvoltage and the potential for ferroresonance. Due to its significant impact, transformer winding configuration is a first order consideration. Therefore, the pros and cons of the commonly used transformer configurations need to be understood to inform selection considering application-specific system characteristics and needs. In this paper, four types of transformer winding configurations are evaluated. The studied winding configurations have been identified from a recent utility survey as the most used ones for three-phase inverter-based DER interconnections in the US. Some of the main concerns related to DER transformer configuration are addressed, including ground fault overvoltage, ferroresonance or overvoltage caused by open phase and open phase detection.

Microgrids are being deployed at a rising rate, primarily as a means of increasing power system resilience. Commonly, a microgrid today includes at least some inverter-based resources (IBRs), and many microgrids have modes or conditions under which they are entirely energized by IBRs. Most microgrids today are deployed on radial distribution circuits, but it is conceivable that they could also be considered for deployment on secondary network systems.

With the proliferation of inverter based Distributed Energy Resource (DER) deployments, especially with advanced grid support functions (GSFs), the risk of unintended islands has remained a significant safety concern among the distribution system operators. IEEE 1547 standard requires DER to "detect an island, cease to energize the area electric power system (Area EPS) and trip within 2 second of the island formation." In addition, because of aggregate impact of high penetration of DERs on system stability, IEEE 1547-2018 revision mandated several GSFs, including abnormal voltage and frequency ride-through and voltage/frequency regulation support capabilities for all DERs. These grid support functions aim to maintain stability during grid-connected operation and island preventions aim to destabilize the network when the grid is not present. These apparently opposite objectives lead to the skepticism about island prevention effectiveness together with grid support from smart inverters. This paper investigates the apparent conflict in objectives and provides answer by revealing the unique relationships between frequency, voltage, active and reactive power in grid following inverter dominated islands and the fundamental differences in inverter’s control during grid-connected and islanded condition. It also explains why ride-through, volt-var, frequency-watt, and volt-watt functions are not expected to impact island detection performance by smart inverters.

Open phase events are not rare in distribution grid with independent phase protection. IEEE 1547–2018 prohibits DER from back feeding into open phase conditions. However, detection of medium voltage (MV) open phase can be challenging for the low voltage connected DER. Depending on the winding of the interconnection transformer, generation and loading level, etc., DER inverter terminal voltage may remain within the normal operating range. This paper investigates an actual open-phase event and evaluates the DER inverters' capability to detect such conditions. Two detection methods based on voltage and current negative sequence components are studied. It is found that DER inverters are able to detect the MV side open phase events in most conditions, especially when the active detection method is utilized, but there are some limitations.

The integration of increasing numbers of larger photovoltaic (PV) power plants brings several challenges to traditional distribution system protection. Two major considerations are managing back-feed and coordinating the inverter response to abnormal conditions.

Renewable energy, especially photovoltaic (PV), plays an increasing role in distribution grids. Due to the variable nature of solar irradiance, there is concern that PV plants may cause power quality problems, such as flicker. This paper describes flicker measurement data from five PV plants ranging from 400 kW to 10 MW, over twelve to twenty-four months. Analysis is provided to estimate flicker contributions from these plants. The contributions were not significant, and results show flicker levels (grid voltage fluctuations) depend more on the PV output power levels than the output variability. We found that PV ramping is too slow to cause light flicker in cases measured. Even the relatively large PV installations do not contribute in a noticeable way because of relatively slow power output changes. Data from this analysis are used to define the PV variability, grid strength and relative plant size that define a borderline of cloud related impacts on feeder voltage fluctuation. This borderline is formulated as a practical flicker screen for PV plants depending on size and grid strength. It provides an easy way to check flicker potential at the time of application processing.

Traditional generation and operation practices are being challenged worldwide by new technologies and alternative ways to plan, design, build and manage power systems. For example, the role of large generating units in the presence of renewable energy needs to be reexamined, especially in places with good renewable resources and aggressive energy policies. This paper presents lessons learned from the preparation, coordination and delivery of a short course on reporting electric generating unit reliability, availability, and productivity. The short course addressed specific industry needs, and was arranged under the leadership of the University of Puerto Rico-Mayaguez. Besides discussing the use of IEEE Standard 762, the course also covered ways to consider variable generation in the future. Puerto Rico's current and proposed renewable energy use was the primary context for the discussion. Assessment results demonstrated that the short course achieved its objectives.

The main interconnection standard for distributed energy resources (DER) in North America, IEEE Std 1547, is being revised. Originally developed assuming a low penetration of DER, the standard has been broadly adopted in the U.S. to guide the interconnection process. However technological and economic advances, especially within the distributed photovoltaics segment, have led to many cases of high penetration levels in the grid, hence, a need to update the standard. Testing and certification requirements are specified in IEEE Std 1547.1 and are also under revision. This article provides an informal report on the status of the revision of IEEE Stds 1547 and 1547.1. It presents the authors' individual views on the revision efforts and is not the formal position, explanation or position of the IEEE. While the specific draft requirements are subject to changes during the standard's balloting process, the paper summarizes those parts of the draft standard that have been relatively stable over the past year.

In 2011, EPRI began a four-year effort under the Department of Energy (DOE) SunShot Initiative Solar Energy Grid Integration Systems - Advanced Concepts (SEGIS-AC) to demonstrate smart grid ready inverters with utility communication. The objective of the project was to successfully implement and demonstrate effective utilization of inverters with grid support functionality to capture the full value of distributed photovoltaic (PV). The project leveraged ongoing investments and expanded PV inverter capabilities, to enable grid operators to better utilize these grid assets. Developing and implementing key elements of PV inverter grid support capabilities will increase the distribution system’s capacity for higher penetration levels of PV, while reducing the cost. The project team included EPRI, Yaskawa-Solectria Solar, Spirae, BPL Global, DTE Energy, National Grid, Pepco, EDD, NPPT and NREL. The project was divided into three phases: development, deployment, and demonstration. Within each phase, the key areas included: head-end communications for Distributed Energy Resources (DER) at the utility operations center; methods for coordinating DER with existing distribution equipment; back-end PV plant master controller; and inverters with smart-grid functionality. Four demonstration sites were chosen in three regions of the United States with different types of utility operating systems and implementations of utility-scale PV inverters. This report summarizes the project and findings from field demonstration at three utility sites.

Introduction A number of distributed energy trends add up to increased interest in microgrids. The objectives and value propositions include access to renewable resources for energy and environment, a more resilient electricity supply amidst storms, optimized energy use by local generation and by local control. Individually these objectives are already being served in various applications and with available distributed energy technologies. A prominent example is roof-top photovoltaic (PV) systems. Widely deployed and custom fit to end-user's sites these systems rely on the grid for balancing differences in output and demand. Also common, battery energy storage and standby generators protect critical processes in applications like hospitals and computer centers. Commercial combined heat and power (CHP) systems usually serve local heat requirements with power to the public grid as a byproduct. Nothing new here, but put them together with a grid connection and a control, and you have the makings of a microgrid. In concept microgrids employ an integrated approach that captures the benefits of several distributed resources. They may provide value to both producers and end users. It's a good concept, but still, the extent of adoption will depend on many factors such as renewable policies, the weather and the price of natural gas. Also future advancements in distributed energy technology and product options are expected to bring improved economics. Ease of grid integration will also be a critical factor in deployment. The challenge, and opportunity, is to create a safe and effective operational collaboration. Utilities can play an important role here. Considered from the broader system viewpoint, harnessing distributed resources can add both flexibility and resiliency to the electric power grid. This primer reviews the drivers for distributed resources and their extension into a microgrid configuration. It explores barriers and challenges for adoption including technical, economic and regulatory. Technologies expected to improve performance or support integration are identified. The primer touches on ownership and business models as well as the likely end-user candidates where a microgrid may contribute to uptime and overall energy efficiency. Finally, it discusses the future for microgrids and points out ways utilities can strategically incorporate them into the larger grid operations.

Conventional power plant performance metrics are designed for dispatchable generation. These can be difficult to apply to variable generators such as wind and solar power. This article describes additional metrics that can be applied to photovoltaic (PV ) power plants and illustrates these metrics using measured data collected from a 1-MW PV plant in Tennessee over a one-year period. The article persuades that new metrics will be needed to measure and effectively employ PV for duty in a traditional generation fleet.

Solar photovoltaics (PV) is the dominant type of distributed generation (DG) technology interconnected to electric distribution systems in the United States, and deployment of PV systems continues to increase rapidly. Considering the rapid growth and widespread deployment of PV systems in United States electric distribution grids, it is important that interconnection procedures be as streamlined as possible to avoid unnecessary interconnection studies, costs, and delays. Because many PV interconnection applications involve high penetration scenarios, the process needs to allow for a sufficiently rigorous technical evaluation to identify and address possible system impacts. Existing interconnection procedures are designed to balance the need for efficiency and technical rigor for all DG. However, there is an implicit expectation that those procedures will be updated over time in order to remain relevant with respect to evolving standards, technology, and practical experience. Modifications to interconnection screens and procedures must focus on maintaining or improving safety and reliability, as well as accurately allocating costs and improving expediency of the interconnection process. This paper evaluates the origins and usefulness of the capacity penetration screen, offers potential short-term solutions which could effectively allow fast-track interconnection to many PV system applications, and considers longer-term solutions for increasing PV deployment levels in a safe and reliable manner while reducing or eliminating the emphasis on the penetration screen.

Solar PV interconnection analyses have historically been addressed by analyzing one or two PV system interconnection requests at a time. As higher penetration levels and numbers of PV systems are realized, the ability to efficiently model and analyze large numbers of PV system deployments and scenarios becomes increasingly important yet difficult. Time and spatial impacts along with uncertainty in the rate of PV adoption must also be considered. Advanced distribution analysis tools are necessary to take into account such factors, and also allow for the quick screening of interconnection requests. This paper discusses some of these issues along with the examples illustrated using an open source distribution analysis program.