Modernization of the common distribution system part II

In the March 2024 issue of T&D World, Ameren Illinois shared valuable lessons learned from deploying distribution energy resources (see Consider the DER Customer Interconnection Process ). One lesson was that even connections that seem straightforward can become challenging. Part II of this series examines four system impacts that Ameren Illinois considers when generation is connected to the distribution system.

When utility customers want to connect their renewable energy generation system, such as solar, to the utility’s electrical distribution system, interconnection testing is typically the first step in maintaining safe and reliable grid operation. This review can range from a simple set of screening questions (for example, to determine whether a residential rooftop solar installation will impact their utility equipment) to a complex N-1 emergency study on a subtransmission system (for example, to measure the impact of a megawatt distributed energy resource system).

The bonding process is a safeguard that prevents reverse power flow in systems designed for unidirectional power flow, and also provides an opportunity to identify and resolve voltage and thermal load violations. In Illinois, the bonding process for regulated utilities is regulated and driven by the Illinois Commerce Commission (ICC) and the Illinois Administrative Code, specifically Parts 466 and 467. The Admin Code, as it is commonly called, defines the bonding 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 screening questions that focus primarily on ensuring that the service equipment is adequate to support the customer’s proposed generation. Larger solar projects are typically screened using a distribution system model, examining the potential grid impacts of connecting distributed energy resources (DERs). If modifications to the distribution system are identified during this study, the connecting customer must pay the utility’s costs to modify the grid and enable the connecting generation in a safe and reliable manner.

Impact on the system

Ameren Illinois considers four system impacts when generation is connected to the distribution system. The first is thermal load, a constraint that utilities must also consider for load. The only difference is that generation could potentially cause an overload in the reverse direction of power flow. For solar, this is most likely to occur when system load conditions are low but solar output is near peak. This analysis is based on the use of minimum circuit load data, which utilities did not have to track at such a detailed level before parallel generation sources became common.

Another limitation is voltage—specifically, the surge from parallel generation sources that feed power into the distribution system. For many years, power flow in the distribution system has been unidirectional. As more distributed generation is supported on the wholesale grid, this bidirectional flow must be managed. Power exported to the grid from a generation source typically causes a voltage spike at the point of connection. In some cases, this spike leads to high voltage for both connected customers and non-generating customers located near the generation source.

A separate but related impact of these DERs is voltage fluctuations resulting from output changes, which are rare in dispatchable generation facilities. Output from solar generation is intermittent—that is, the sun is not always shining. This makes the generation source both unpredictable and uncontrollable. These voltage impacts must be identified to avoid passing on the network costs incurred by parallel generation connections to the rate base.

The final issue to consider is the possibility of reverse power flow through devices in the system that were not designed or intended for this condition. Protective devices in this category include electromechanical relay circuit breakers and hydraulic reverse circuit breakers. These devices are mechanically controlled and the reclosure delay of such devices is variable due to environmental conditions. Relay-controlled devices can be retrofitted with modern relays to address the reverse power flow problem, but often protective devices must be upgraded to modern electronically controlled devices. This is to ensure that the reverse circuit breaker does not open and close again before the inverter detects a loss of utility power and ceases generation, which would cause the two power sources to be out of phase.

Unintentional insularity

In addition to replacing the relays controlling the protective devices, additional protective schemes are sometimes needed to prevent inadvertent islanding. This may include additional measurements within the substation to enable the relays to detect and respond to the presence of generation and may be used to facilitate the tripping of direct transfer (DTT) to large direct distribution voltage connections. DTT is a fast communication and protection function initiated by the protective relay before any generation occurs. When the device trips to clear the fault, it sends a signal to the protective device at the point of connection, which will cause the device to open. The purpose of DTT is to quickly disconnect generation from a utility system fault so that it does not cause any unexpected effects (such as overvoltage or islanding) on ​​other customers connected to that circuit.

Voltage regulation devices, including substation transformer tap changers, are also susceptible to reverse power flow problems. Some of these devices are not designed for bidirectional voltage regulation. In many cases, this can be fixed by adjusting the settings of the existing device, but in other cases it requires replacing the controller or device.

Generation measurement

Renewable energy projects often require the construction of interconnection facilities at the point of connection. The type of interconnection equipment depends on the size of the project. Smaller residential customer systems often interconnect without additional interconnection facilities, while larger systems behind the meter require generation metering. This metering measures the output of the generation. The resulting data, combined with data from the revenue meter, is used to identify the full load on the facility, which is critical for system planning. This meter also includes real-time communication with the utility’s supervisory control and data acquisition (SCADA) system to provide visibility to system operators and to 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 voltages (4.16 kV to 69 kV line-to-line). These connections require a protective device at the point of connection that performs multiple functions. The protective device is connected to SCADA and can provide real-time voltage and power flow at the point of connection. The SCADA functionality of the device also allows distribution operators to temporarily disconnect large generating facilities during switching events or to restore power 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 protection against inadvertent islanding when an upstream device trips to clear a fault.

As DER penetration in the distribution system increases, this type of equipment will become common in most substations as older equipment is replaced. Until then, this type of work will be a common feature of DER interconnection projects.