For many years, people in the utility business have looked at their delivery system as two distinct entities: transmission and distribution. The transmission network is a modern, smart, and optimized system. The transmission grid can generally deliver capacity and energy between any two points, in either direction, with few issues. Utilities routinely trade energy in either direction even where the only interconnection has multiple other utilities in the path between the exporter and importer.
By contrast, the distribution system, often referred to as a “black hole” is seen as a one-way network that has limits and constraints on its ability to deliver energy. In some major cities, parts of the distribution system may be almost 100 years old. Outages often must be reported by someone calling to report that their “lights are out.”
Why does this stark contrast exist in such an important system? What can be done about this – and when might we see real change?
The answer may be simple, but the impacts could be large. Transmission systems started in much the same form as the current distribution system exists. Transmission lines were built to connect generation to loads with little ancillary equipment to protect them.
The photo shows a transmission line that was built in about 1910 that went from a hydro plant on the Kootenay River in British Columbia to gold mines in Rossland, about 32 miles away. The line operated at 32 kV and at that time was claimed to be the longest high voltage line anywhere. Little “roofs” on each pole protected the insulators from snow that someone thought might cause a short circuit in the line.
As the transmission system grew, standards for reliability were established and maintained. Communications soon became a critical factor in system operation. Protective equipment at each end of the line could measure voltages and currents in the line and could detect a fault – directionally on the line. By adding a communications link and comparing similar measurements at both ends of a line, the protection system could identify a faulted line and take it out of service. The communications system between both line ends provided critical information for this process. As the systems advanced, isolating and clearing faults became time sensitive. Leaving a fault on the system for more than a short time could cause the entire system to collapse. Protection systems were designed and implemented to address this issue. Some systems now can identify and clear a single-phase fault. Many utilities found communications to be of such importance that they built and operated dedicated microwave radio systems exclusively for transmission system protection. In recent times, these communications systems have been largely migrated to fiber optics, but this capability has enabled these systems to operate reliably as they do today.
The distribution system was largely ignored in this respect because dedicated communications for small, distributed loads was cost prohibitive. But we are now at a state where this is changing rapidly. The new distribution system may become a system that will have flexibility to do many tasks that have been impossible in the past.
One example of older methods stands out in my memory. Many small distribution substations exist in what is known as a “loop” configuration. They often have a transformer connected directly to an incoming line. If a fault is detected inside the transformer, it is essential that the incoming line be tripped immediately at the sending end to minimize damage to the transformer. In a transmission network, a transfer trip signal would be communicated to the sending end, and that would trip the line circuit breaker, removing power from the faulted transformer. But in older distribution systems, where communication is not available, a large spring-loaded bar may be installed that applies a short circuit on the incoming line. The protection system at the other end sees a line fault and trips the line. Problem solved – in a very crude way.
Recently, the addition of distributed energy sources has caused issues that will drive a dramatic change in the distribution system. These systems have caused problems under the old model, but communications have now advanced to the point that cost-effective measures may easily be undertaken that will bring a full-scale change to the distribution system.
Consider a distribution feeder with many solar-powered sites along the line. Should a fault occur near the remote end of the line, it is possible that the DER sites along the way will supply all fault current, and the substation supplying the feeder may not see the fault at all. This fault would not be cleared, potentially causing real damage – or fires. Utility distribution planners see many similar issues and their only recourse has been to place restrictions on the numbers and capacities of DER facilities on the line. In doing so, they have caused frustration and anger among people with intentions to supply clean energy to the grid. The addition of communications will enable full integration of DER facilities, allowing protection systems to be utilized. This, in turn, should enable maximized use of DER capacity to support a transition to clean energy.
The AMI or smart meter initiative has been an impressive start to enable communications. Technically, a utility can set up a mesh of customer meters in an area where they have direct communications with only a few of the meters. But the meters can interconnect among themselves and provide a full communications system for the utility, reporting on real time demand, voltages, and currents as well as billing data at all customer sites. This form of communication may provide a valuable link for metering, control and protection in future.
Some utilities have purchased cellular spectrum, intending to manage their system on a private network, while others are using a variety of other methods for communications.
The real value of new communications facilities in the distribution system, however, may go well beyond the electric system itself. We have lived more than 100 years with a system designed for the short peak demand capacity that MAY happen at some point in the year. The average demand on the grid is typically about half of the peak. By using communications to manage and optimize the entire system, including demand, the system can operate closer to peak capacity on a continuous basis. This increase in delivery capacity will be a valuable asset for utilities, and it will help to maintain low costs. Generac Grid Services has demonstrated that many load devices can be managed for the grid without impairing the operating needs of the customer. Similar management of voltages can be used to manage and optimize system losses.
The skills being developed within Generac Grid Services will be ideal in building this grid of the future. This opportunity to include customer devices as an integral part of an optimized system, where customers are paid for their contribution, will be a challenge, but a rewarding achievement. The transmission and distribution systems, along with the supply and demand will be operated as a single optimized and seamless system. In such a system, everyone wins. Costs are minimized, and customers become a part of the process to fully optimize operations.
The answer may be simple, but the impacts could be large. Transmission systems started in much the same form as the current distribution system exists. Transmission lines were built to connect generation to loads with little ancillary equipment to protect them.
Energy without Hot Air 