The Future Is Now

Aug. 1, 2012
Chattanooga melds fiber optics, distribution automation, voltage optimization and AMI for a smarter grid.

Not exactly a household name, the municipally owned Electric Power Board (EPB) has been drawing attention lately for the high level of automation it has put in place for what it is calling its “smarter grid.”

A power distributor for Chattanooga, Tennessee, U.S., the EPB has been working with automation technologies since the early 2000s and, after years of studying technologies, began implementing a more defined smart grid strategy in 2007. The plan included several components and was slated for a 10-year construction period. While implementation was in progress, the utility applied for and was awarded a matching stimulus grant by the U.S. Department of Energy to expedite the construction and implementation of the plan. What would have been a 10-year build-out became a three-year plan.

Even in a state of partial completion, the utility has seen results in increased reliability and power quality, better asset management, and operational and cost-efficiency improvements. Devices along the utility's smarter grid communicate with each other, the customer and the utility in near real time, thanks to the ultrafast fiber-optic network communications backbone. In many cases, the grid can heal itself with little or no human interaction, and its components can interact with each other, customers and the utility for maximum performance and predictive analysis.

What Are the Components?

It all starts with the ability to communicate quickly and reliably with any location on the system. This communication is achieved with the fiber-optic network deployed throughout the utility's service territory.

By adding in distribution automation, voltage optimization, advanced metering infrastructure (AMI), smart grid management software and a new supervisory control and data acquisition (SCADA) system, the grid becomes more reliable and operates more efficiently, thus helping to mitigate the rising cost of power. It also can provide analytics that allow for improved power quality, offer more options for customers and be a tool for the community's economic development efforts.

More Reliable

The utility's smarter grid is already proving to be a reliability benefit, which is critically important for a municipal utility. Several studies have been conducted on the effect of power reliability on communities. Studies by the University of California Berkeley Lab, the Electric Power Research Institute and others identified the national costs of outages to be roughly US$80 billion pe year, comprised mostly of costs to businesses and economies in general. Applied to the Chattanooga area, it could be estimated power outages result in an annual cost of $100 million to the community as a whole. This cost is one of the major reasons EPB put together a comprehensive plan for building an intelligent, self-healing and interactive distribution system.

The 6,450 miles (10,380 km) of high-speed fiber-optic cable, of which 65% is steel lashed, provides a 5-msec average roundtrip time to devices across the network. This high-speed capability, matched with sensitive and interactive devices on the network, means analytics and action can be more responsive than ever.

EPB developed a robust plan for automation that included completing the implementation of fault isolation and service restoration (FISR) technology for its 46-kV subtransmission system and implementing FISR technology throughout the service territory on its 12-kV distribution system.

Deployment Approach

After evaluating several different technologies for automating the 12-kV system, EPB selected S&C's IntelliRupter PulseCloser and IntelliTeam SG Automatic Restoration System. IntelliTeam SG is a field-proven, universal smart grid solution that uses embedded intelligence to automatically reconfigure the distribution system after a fault and quickly restore service to segments of the feeder not affected by the fault. IntelliTeam SG substantially reduces customer minutes of interruption, markedly improving this measure of reliability. Each Intelli-Rupter is equipped to communicate with its peers and the SCADA system over the fiber-optic network. Communication between switches has been recorded as fast as 2 msec and consistently average 7 msec.

EPB planning engineers analyzed each 12-kV feeder to identify locations for automated switches. To maximize the customer benefits, EPB targeted an average feeder section to have 150 customers, a 750-kW load and 3,500 pole-line ft (1,067 m) of exposure. The final results were an average of 133 customers per line section, an 892-kW load, 3,345 pole-line ft (1,020 m) of exposure and an average of seven switches per 12-kV feeder.

Planning engineers then determined protective settings for each switch location based on a set of standard time-current coordination curves. EPB focused a great deal of effort on the installation process, including not only the design and construction of the electrical equipment but also the communications equipment, commissioning of the equipment and automation of the switch teams. To integrate the electric and communications business process, EPB leveraged existing workflow processes and fiber-to-the-home provisioning processes for communications equipment. EPB's installation of IntelliRupters included one of the first integrations of fiber-optic communications.

Learning the Way

After several revisions to the process, EPB began switch installations on a small scale at the end of 2010. Based on lessons learned from the initial installations, the process was improved and several more switches were installed. There were 19 versions of the process before it was considered final.

Once the process was finalized, EPB quickly ramped up installations to approximately 80 per month in early 2011. As switches were installed, fiber was run to each switch, with communication through Alcatel-Lucent's Optical Network Terminator, and protective settings were installed. The communication between each switch and the SCADA system was then tested for each location. Once the switches were verified as communicating properly, they were commissioned by operations and officially placed in service. At this point, a switch could be operated remotely by SCADA and could interrupt faults, but it was not operating as an FISR team. After all the switches on a feeder were in service, they became candidates for automation.

Seeing Benefits

In the most violent year of storms in EPB's history, measurable results were realized even as the smarter grid was in its partial state of completion. At the time of a Labor Day storm in 2011, a remnant of Tropical Storm Lee, only 54% of the planned 1,200 S&C IntelliRupter automated switches were installed and less than 20% were configured into automation teams. While 63,000 homes and businesses were interrupted, 16,000, or 25%, avoided interruption altogether and an additional 9,000 customers, or 7%, experienced less than a 2-sec interruption. The electric system's ability to heal itself through automated fault detection and isolation during this storm resulted in the utility avoiding 1,917,000 customer minutes of interruption.

In the months following the year of violent storms, EPB's 12-month ending system average interruption duration index (SAIDI) dropped 24%, from 109 minutes to 82.5 minutes, since December 2011.

More Efficient Operations

While AMI and smart grid are synonymous in some power systems, EPB's AMI deployment is considered a small, though powerful, component of the overall plan. The AMI deployment will provide 15-minute interval consumption data to customers within 15 minutes of when the energy is used, thereby allowing customers to better understand their energy usage and make more informed decisions.

While only partially complete, the AMI project is already helping with operational efficiency during an especially critical time. After devastating tornados knocked out power to 75% of the utility's service territory in April 2011, smart meters enabled EPB to avoid 250 truck rolls during restoration. While the outage management system (OMS) was still reporting outages at these hundreds of locations, the utility was able to remotely ping meters to determine power had been restored at 250 locations, allowing the utility to use valuable resources in areas that truly needed them.

When complete, EPB will have installed 10,000 RSUGs (remote switch under glass), disconnect equipment integrated into the meter (hence, under glass). This will not only allow the utility to respond more quickly to customer requests, it also will result in cost savings and pay for itself in less than two years.

Better Power Quality

Each of EPB's 1,200 automated switches provides a pole-top telemetry point on the electric grid, sending amps, volts and power factor to the SCADA system. These points will provide accurate inputs to the distribution management system, which is scheduled to be implemented in early 2013. They are already providing valuable insights into the electric system operations.

Recently, a large commercial customer contacted EPB with a concern about its computer-controlled equipment tripping off-line. EPB was not aware of any voltage anomalies on the circuit serving this customer, but it queried the nearest Intelli-Rupter to the customer's service point. The investigation revealed the voltage had dropped to 70% of nominal for one cycle. The time of this event was correlated to a fuse blowing on a nearby circuit. The information was provided to the customer with a recommendation to review the settings on their equipment and possibly adjust the trip values to something less sensitive.

This proved to be a good lesson for EPB in the need to understand more deeply the performance of the electric grid but also to recognize that customers' electric requirements will continue to grow as their equipment becomes more automated.

Additionally, the AMI deployment provides the utility with voltage readings to help it better understand the deployed facilities and correct problem s proactively. One of the early phases of testing AMI outage alerts involved a comparison of the outage alerts issued by AMI meters with an identified cause. The intent was to reconcile the outage alerts with an outage in the OMS (planned or unplanned), a momentary outage recorded in SCADA or planned meter activity (disconnect/reconnect).

One of the outage alerts could not be associated to any of the predetermined causes. A query of the meter reporting the outage indicated the customer did not actually lose power, but that the voltage had dropped below 80% of nominal, which EPB had set as the threshold for a power outage. Further investigation of the consumption showed power was only being used at night, and the drop in voltage corresponded with the time at which power was being used.

Combining these two pieces of information with the customer record that stated this was service to billboard lighting revealed a possible open-neutral condition, which was verified and repaired with a field visit. The valuable lesson learned here was EPB could use AMI data to develop “signatures” of power-quality conditions, develop queries to search for them and initiate corrective actions — in some cases, before the customer was aware of the problem.

More Customer Options

Wheels are in motion for the implementation of a 5,000-home pilot that will take advantage of the grid's new two-way communications capabilities to offer new options for customers. Offerings will vary from traditional time-of-use rates, allowing customers to modify their usage behavior for cost savings, to products designed to reduce peak demand without customers needing to take any action at all.

The Need for Speed

Is reading meters all that needs to be done? Of course not. But, the speed and bandwidth provided by the fiber optics allow for improvements in so many areas in addition to providing customers with near-real-time energy-usage information. For example, the speed and low latency of the network allowed a recent firmware upgrade to all of the IntelliRupter switches to be completed in roughly one-and-a-half days. Previously, the same upgrade would have required 600 work-hours to upgrade in the field and involved numerous field workers.


The full implementation of EPB's electric grid will result in an increase of approximately 400% in SCADA endpoints. To support the additional points, EPB recognized the need to upgrade its SCADA system. Implemented in March 2012, the new SCADA system enables EPB to fully leverage the Internet protocol communications infrastructure provided by the fiber-optic network.

Economic Development

Independent economic assessments have forecasted EPB's investment to net economic and social benefits of $1.2 billion and create 3,700 jobs in Chattanooga. While it is no secret that reliable, affordable electric power is a critical component for site selectors and others looking to relocate to or expand business in an area, Chattanooga is already seeing tangible evidence of this and looking forward to more.

Jim Glass ([email protected]) has more than 25 years of transmission and distribution experience, serving in management positions at both Florida Power & Light and EPB. His past roles have included manager of distribution control center and manager of emergency preparedness (hurricane response) at Florida Power & Light. Today, Glass is EPB's manager of smart grid development. He holds a bachelor's degree in industrial engineering from the University of Tennessee.

Lilian Bruce ([email protected]) is a senior strategic planner for EPB. A former energy analyst for Tennessee Valley Authority, her industry experience ranges from trading to energy transmission. She holds a bachelor's degree in architecture from Syracuse University and a MBA degree from the University of Tennessee at Chattanooga.

Companies mentioned:

Alcatel-Lucent |

Berkeley Lab |



S&C Electric Co. |

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