When the goals of a utility and its host community aren’t in sync, breakups happen.
Utility 2.0 and the Dynamic Microgrid
Superstorm disruption calls for a new utility architecture.
remains depressed until the electric infrastructure is restored. Often a VLSE’s effects span across an entire region of the country.
The term VLSE encompasses not only meteorological events; it can be any large-scale event, even including earthquakes. Thus, individual electric utilities often can’t adequately plan for dealing with VLSEs, nor can they undertake the necessary infrastructure restoration work. Advance planning for something of this magnitude or responding to its aftermath requires close coordination and collaboration at federal, regional, state, and local levels.
Policies and regulations that facilitate collective action also are vital. Moreover, grid modernization (smart grid) technologies alone can’t adequately improve and sustain the reliability, resilience, safety, and security of the electric system during a VLSE. Rather, their resolution must integrate people, technologies, and processes to maximize effectiveness in preparing for such responses.
Let us consider a typical storm scenario and the typical utility response.
As most hurricanes (category 3 and above) travel up the East Coast of the United States, they’re accompanied by heavy rains and winds, the latter sometimes reaching more than 100 mph. When such a hurricane hits land, the severe winds bring down trees that disrupt and destroy sub-transmission lines, and, more particularly, distribution lines, so creating a storm-emergency scenario.
Such events happen relatively often in the Eastern and Midwestern states, and each time they affect many thousands or even millions of people. Resulting outages affect many customers because much of the distribution network is configured radially. When something breaks, all the downstream loads lose access to power. Moreover, much of our power comes from large centrally based generation, with long transmission lines that serve large regions; distributed generation still is rare. And even where distributed generation is installed, it often isn’t designed to operate in an islanded mode.
Depending upon the level of sensing or controls available in a given area, operators at the utility’s distribution control center will be aware of some outages through their SCADA (supervisory control and data acquisition) systems. However, unless an AMI (advanced metering infrastructure) system is fully integrated into the OMS (outage management system), the operators generally will have little understanding of the extent of the outages until customers start calling with reports.
As the utility learns about the full extent of an outage, staff members start prioritizing the needed repairs and restorations. Every utility has its own prioritization sequence that generally is based upon criticality and number of customers that have lost power, with restoration prioritized for main lines first before the lateral lines, and so on.
As equipment needs to be deenergized or reenergized, operators at the control center must develop switching orders to assist the field crew in isolating the equipment for reconnecting to the grid. This task is critical because if too much load is picked up simultaneously, then the lines can overload and trip again.
Repairs are made as needed; sometimes badly damaged equipment might need to be replaced.
The reconnecting process can be a delicate operation due to the lack of sensing equipment and the operator’s limited understanding of the exact amount of load