The electric grid consists of two significant and highly different sections: Transmission and distribution (T&D). The transmission system is relatively modern and efficient, but the distribution system is aging and will require considerable changes to modernize.
T&D Systems Are in Highly Disparate Stages
Prior to about 1980, transmission needs grew at about 7% annually, doubling in capacity every 10 years. At any given time, half of the transmission system was less than 10 years old. Voltages increased, and technology was added to protection systems to create a high-voltage network that can deliver power in almost any direction where there is available capacity. Today’s transmission system is relatively sophisticated and is well-optimized with the large generation facilities. Control centres have the capability to fully monitor and control these systems, while protection systems monitor operations and provide capability to identify and isolate system faults—often within less than a few electrical cycles. The ability to rapidly clear faults has allowed an increase in delivery capacity of the system and protection systems have become an important part of grid operations.
The distribution system, for the most part, is in almost the exact opposite position as the transmission system. Distribution delivers power to customers from local substations. Typical voltages for distribution are less than 44 kV. Large industrial customers may be connected directly to the transmission system, while commercial and smaller industrial customers may be connected at the primary distribution levels. Residential customers are typically connected at 120 V, 208 V or 240 V. These low voltages are created with local transformers that provide capacity for a few homes or small stores. Communications within the distribution system has been minimal until the recent implementation of smart meter technology. Additional barriers exist at this level because even these systems generally serve the billing departments before operations receive needed data. Fault clearing has generally been based on overcurrent measurements taken at the substation supplying the distribution feeder. This form of protection operates much like a fuse or a home circuit breaker. It is crude setup and can be a slow means of clearing faults that occur.
T&D Approach Modernization from Opposite Sides of the Table
The transmission system is designed for gradual maintenance and updates. The system is generally capable of delivering power between any two points on the grid (in either direction) with little need to take control action—other than to ensure that no part of the system is overloaded. The National Electricity Reliability Corporation (NERC) requires that the system be operated with reserve capacity to ensure that any single contingency loss will not lead to a large-scale collapse or failure. Operations planners study system conditions prior to taking any line out of service for maintenance. While the single line removal may have no impact, these studies ensure that a subsequent fault during a maintenance outage on a line does not lead to a significant problem. The math behind this type of operation is complex but it is important in maintaining system reliability.
The distribution system, however, is not as nimble. It is designed to deliver the expected peak power needed from a substation to all customers connected to the feeder. Any injection of power from distributed generation or storage systems along the feeder may impair existing operations in several ways and ultimately increase risk for the utility:
- Loss of power: Solar inverters are expected to shut down if there is a loss of power from the substation. This is generally the result of a loss of reactive power delivered by the substation causing inverters to stop operations. Such an event is an inherent characteristic of many inverters—they will not operate without a local supply of AC power connected. Inverters that are also used for backup supply during outages may not operate this way. Some utilities have set conservative standards limiting the capacity of connected inverters to significantly less than the minimum expected 24-hour demand from customer loads. This concept ensures that the loss of substation capacity will result in a collapse of the inverters that are operating; however, this concept also severely restricts the distributed capacity that can be connected on a feeder.
- Fires from reactive power: Fires are a threat to the utility. A generator on a line with many solar systems may supply enough reactive power for the inverters to maintain operations even if the line is tripped at the substation. In this case the fault may not be isolated, potentially causing local fires.
- Fires from distributed energy resources (DER): DER are increasing, which could also cause fire dangers. The problem may be that fault current is supplied by the distributed generation or storage, and the substation overcurrent relays will simply not see the fault, again raising the risk of fires at the fault site.
- Safety: The fourth and perhaps most difficult issue is one of safety. A line may be tripped of at the substation due to a fault, but of the distributed systems might continue to power the feeder, even at a reduced level. Power line technicians dispatched to perform corrective repairs could easily be at risk.
Utilities Hedge Against Distribution System-Related Risks
Some utilities are faced with high penetrations of distributed generation and storage have resorted to shutting power off to entire areas during periods when fire risks are severe and winds are strong. With increasing use of distributed generation, these problems must be solved with solutions that provide a safe operating state, regardless of local wind and weather. Protection systems will be required to address the changing environment. Communications between DER sites and the substation will also be needed. In the past, such a communications system was expensive, but with modern technology, secure communications can be implemented at a cost-effective price.
Generac Grid Services’ Technology Can Help
The key to resiliency while keeping fire risk low is grid orchestration technology. Utilities should equip distributed sources, either generation or storage that have the capacity to provide either voltage or power support to the grid, with systems that can identify nearby fault conditions while relaying information to substations in a form that can be applied directly. There are a few companies that manufacture and supply protection systems for utilities that have shown real leadership in this area.
In several columns, I have addressed the strong need for partnerships between utilities, companies providing optimization and control, and utility customers. In this case, the opportunity for partnerships extends to companies that provide innovative protection systems for the future. The electric grid is the largest system on the planet, and in the past, the subsections of the grid have been able to operate almost independent of the others. With the rapid growth of distributed generation, storage, and demand management, time will soon mandate the need for smart partnerships that can be profitable for all participants.