What Makes Substation Automation a Requirement Now?

By Frank Hoss, GE Energy

What makes substation automation different today from what it was five, 10 or even 20 years ago? What does the intelligent grid have to do with it? Clearly, substation automation is not new. It has been deployed in major or critical substations for at least 20 years. So what makes it a requirement now?

First, let’s look at the operating environment in which many utilities will find themselves in the next five to 20 years. Up to the present, providing electricity to consumers has been a stable, orderly, mono-directional process from major generating stations, through transmission and distribution, to industrial, commercial and residential customers. But the winds of change are blowing! Politically, legislatively, business-wise, and across society, the emphasis is being placed on being environmentally conscious. For the utility, it means moving away from coal-fired power plants that produce greenhouse gases, investing in renewable energy, and focusing on energy efficiency and demand-side management (DSM) efforts.

Presently, 28 U.S. states have either adopted or are about to adopt renewable portfolio standards that require anywhere from 10 percent to 33 percent of the utilities’ energy sources to be renewable (e.g., wind, solar). Many utilities that have recently tried to get approval for new coal-fired power plants have failed. They’ve been told to invest in renewables and DSM. All of this is occurring at a time when only about one-third of the expected electrical capacity to meet the needs in the next 15 years is under development. Combine this with the transmission grid congestion that is occurring and the mere fact that it takes about 10 years to commission a new transmission line. FERC has recently had to declare national transmission corridors to try and speed up this process.

This operating environment changes the utility, substation and consumer environment. Large investments are being made in wind and solar generation, at both transmission and distribution levels, and until sufficient energy storage devices are available, utilities have to address the problems of intermittency. A recent California Energy Market study of the deployment of 33 percent renewable portfolio standards will require an additional 1,700 MW of quick-start generation, 40 additional transformers/substations, 1,860 megavolt amperes reactive (reactive power) in voltage support, and day-ahead forecast errors upwards of 100 percent greater. Cal-ISO will also need 6,000 MWh of additional flexibility (up from the present 4,300 MWh). Residential consumers will have to support a portion of this through DSM. Florida Power & Light Company has proved that residential DSM can be successful, with approximately 1,000 MWh available from about 750,000 customers. Distributed generation will be much more prevalent in the next five to 10 years, likely achieving levels of 15-plus percent. This will require the grid to become much more flexible.

It is through substation and grid automation that utilities will build the needed elasticity into the electrical grid.

Major and critical substation automation has been deployed for at least 20 years. For most utilities, the reason that automation hasn’t been extended to other substations, other than clearly not having an operational need, has been the major costs associated with automation. So, what has changed beyond the operational necessity that now makes substation automation “affordable”? There are three primary drivers:

  • Maturing technology,
  • More initiatives, and
  • Communications availability.

The last five years have seen technology develop and mature toward open, non-proprietary systems architecture and a wider acceptance of industry standards such as service-oriented architecture (SOA) and IEC 61850 for substation automation. For one major substation equipment vendor (as well as for utilities), this potentially means having only to support a handful vs. about 150 legacy protocols, resulting in significant cost savings.

Many more industry-wide initiatives are under way to help utilities address their changing operational needs. Examples include Distribution Vision 2020, EPRI Intelligrid, DOE GridWise Aliance, CEC Advanced Automation, and the Smart Energy Alliance. Each of these organizations focuses on providing tools and solutions to operate an elastic grid.

Finally, advanced metering requires the deployment of a two-way communications solution throughout the distribution network. In addition to being a requirement, it has become “affordable.” Many utilities have quickly come to the understanding that additional incremental investments to this metering communications solution will allow them to communicate, control and automate many distribution grid devices, including those found in substations.

The operational need for more substantial and wider deployment of substation automation is now a reality. Intelligent grid efforts have provided the infrastructure. To realize the benefits which an elastic grid will bring, requires substation automation now.

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Frank Hoss is GE Energy’s Americas marketing development manager for T&D. GE Energy provides a wide variety of transmission and distribution electrical equipment, software, services and integrated solutions.

GE Energy is a member of the GridWise Alliance, a broad industry coalition committed to advocating changes discussed in this column. For more information, visit: www.gridwise.org.

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