In the March 2024 issue of T&D World, Ameren Illinois shared valuable lessons learned from its distribution energy resources enablement (see Consider A Customer DER Interconnection Process article). One takeaway was even interconnections that appear straightforward can become a challenge. Part II of this series explores the four system impacts Ameren Illinois considers when generation is being connected to its distribution system.
When a utility’s customers want to connect their renewable generation system, like solar, to the utility's electric distribution system, an interconnection study is usually the first step in maintaining safe and reliable operation of the grid. This review may take several different forms — ranging from a simple set of screening questions (for example, to determine whether a residential customer's rooftop solar installation will cause impacts to their service equipment) to a complex N-1 contingency study on the sub-transmission system (for example, to measure the impact of a megawatt-scale distributed energy resource system).
The interconnection process is a safeguard that prevents reverse power flow on systems designed for one-directional power flow, as well as the opportunity to identify and address voltage and thermal loading violations. In Illinois, the interconnection process for regulated utilities is governed and driven by the Illinois Commerce Commission (ICC) and Illinois Administrative Code, specifically parts 466 and 467. The Admin Code, as it is commonly referenced, defines the interconnection process for each project based on the size of the generation system proposed in the application.
Smaller systems (residential and small commercial) are screened using a simple set of review questions that mostly focus on ensuring service equipment is adequate to serve the customer's proposed generation. Larger solar projects typically are reviewed using a model of the distribution system, investigating for potential grid impacts resulting from the distributed energy resource (DER) interconnection. If distribution system modifications are identified during this study, then the interconnection customer must cover the expenses incurred by the utility to modify the grid and enable the generation to connect in a safe and reliable manner.
System Impacts
Ameren Illinois considers four system impacts when generation is being connected to its distribution system. The first is thermal loading, a constraint that utilities must also consider for load. The only difference is generation would have the potential to cause an overload in the reverse power flow direction. For solar, this is most likely to occur when system loading conditions are low but solar output is near its peak. This analysis relies on the use of minimum circuit loading data that utilities did not need to track at such a granular level before parallel generation sources became common.
The next constraint is voltage — more specifically, overvoltage from parallel generation sources injecting power to the distribution system. For many years, power flow on the distribution system was one directional. As more distributed generation is served on the wholesale grid, this two-way flow must be managed. Power exported to the grid from a generation source typically will cause a rise in voltage at the point of interconnection. In some cases, this increase leads to high voltage for both interconnection customers and non-generation customers located near the generation.
A separate but related impact of these DERs is voltage fluctuations from output variations that are uncommon in dispatchable generation facilities. The output from solar generation is intermittent — that is, the sun does not always shine. This makes the generation source both unpredictable and uncontrollable. These voltage impacts must be identified to avoid passing grid costs incurred by parallel generation interconnections to the rate base.
The final issue to consider is the potential for reverse power flow through devices on the system that were not designed or intended for this condition. Protective devices in this category include breakers with electromechanical relaying and hydraulic reclosers. These devices are mechanically controlled and the reclose delay on such devices is variable due to ambient conditions. Relay-controlled devices may be able to be retrofitted with modern relaying to address reverse power flow, but often the protective devices need to be upgraded to modern electronically controlled devices. This is to ensure a recloser does not open and reclose before an inverter is able to detect a loss of utility power and cease generation, which could cause the two power sources to be out of phase.
Unintentional Islanding
In addition to replacing the relaying that controls protective devices, sometimes additional protective schemes are needed to prevent unintentional islanding. This may include additional metering inside the substation to allow relays to sense and react to the presence of generation and can be used to facilitate direct-transfer trip (DTT) to large distribution voltage direct interconnections. DTT is a high-speed communication and protection function initiated by a protective relay device upstream of any generation. When the device trips to clear a fault, it sends a signal to the protective device at the point of interconnection that will cause the device to open. The intent of DTT is to rapidly disconnect the generation from utility system faults, so it does not cause any unexpected impacts (such as overvoltage or islanding) to the other customers connected to that circuit.
Voltage regulation devices, including substation transformer load-tap changers, are also subject to reverse power flow concerns. Some of these devices are not designed to regulate voltage bidirectionally. In many cases, this can be rectified through a settings adjustment to the existing device, but in other cases, this requires either replacement of the controller or the device.
Generation Metering
Renewable generation projects often necessitate the construction of interconnection facilities at the point of interconnection. The type of interconnection equipment depends on the size of the project. Smaller residential customer systems often connect with no additional interconnection facilities, while larger behind-the-meter systems require generation metering. This metering measures the generation output. The resulting data, combined with revenue meter data, is used to identify the full site load critical for system planning. This meter also includes real-time communications with the utility's supervisory control and data acquisition (SCADA) system to provide system operators visibility and enable distribution automation schemes to account for behind-the-meter generation when performing self-healing switching operations.
Some renewable generation systems connect directly to the distribution system at medium or high distribution voltage (from 4.16 kV to 69 kV line to line). These interconnections require a protective device at the point of interconnection, which serves multiple functions. The protective device is connected to SCADA and can provide real-time voltage and power flow at the point of interconnection. The SCADA functionality of the device also enables distribution operators to temporarily disconnect large generation facilities during switching events or for outage restoration as needed to maintain grid stability and safe working conditions for electrical workers. At Ameren Illinois, this device is used to facilitate DTT functionality, which provides additional safeguarding against an unintentional island when an upstream device trips to clear a fault.
As DER penetration continues to increase on the distribution system, these types of devices will become commonplace in most substations as older devices are replaced. Until then, this type of work will be a prevalent component of DER interconnection projects.
