Navigant Research Blog

Resilience Movement Hits the West Coast

— August 1, 2016

GeneratorThe focus of state programs designed to boost resilience have been microgrid and nanogrid projects on the East Coast launched in response to extreme weather events such as Hurricanes Irene and Sandy. Since 2011, a parade of states have launched state-funded programs: Connecticut; Maryland, Massachusetts; New Jersey; New York, Rhode Island, and Washington, D.C., among others. A quick glance at some statistics underscores why governments see value in public investments to improve the resilience of regional power grids.

Since 1980, the United States has sustained more than 144 weather disasters with damages reaching or exceeding $1 billion each. The total cost of these 144 events exceeds $1 trillion, according to the U.S. Department of Commerce. According to the president’s U.S. Council of Economic Advisers and the U.S. Department of Energy (DOE), severe weather-related electricity outages cost the U.S. economy more than $336 billion dollars between 2003 and 2012.

Resilience in San Francisco

The perception that this resilience movement is an East Coast phenomenon is being challenged by a program launched in San Francisco. Rather than being focused on threats that can be anticipated via new weather forecasting techniques, the program is focused on a threat somewhat confined to the West Coast: earthquakes.

What would happen to the electricity and natural gas infrastructure of San Francisco if an earthquake equivalent to the 1906 event occurred today? A project developed by the City and County of San Francisco’s Department of the Environment looked into that question. Entitled the Solar+Storage for Resiliency project, the early results of modeling are quite sobering. While 96% of the city’s consumers could expect their electricity to be back online within 1 week, it would take as long as 6 months for the natural gas infrastructure to be fully operational. (To get back to full-scale provision of electricity would take 1 month.)

Reports from Connecticut showed that natural gas continued to flow through extreme weather, hence its focus on fuel cells and fossil fuel generation as the cornerstone of its efforts toward resilience. San Francisco is taking a different approach, focusing instead on distributed solar PV linked to advanced batteries while incorporating existing diesel generators into the solution mix.

After an extensive and interactive mapping exercise located critical facilities throughout San Francisco, sites were analyzed for available rooftop space for solar PV and the logistics of installing batteries. Projects that could be installed under existing regulatory restrictions were also prioritized. The end result is roughly a dozen projects scattered throughout the city that would offer resilience in the most sustainable manner possible using current technology. So far, funding for initial groundwork for this microgrid portfolio has come from a $1.2 million grant from the U.S. DOE’s SunShot initiative.

Emergency Response Programs Lead to Economic Opportunity

Though a common perception is that diesel generation is the most reliable backup power supply, reports from the field beg to differ, as failure rates can be extremely high. The vulnerability of San Francisco’s natural gas infrastructure also required a different approach. Given recent advances in smart inverters capable of safe islanding and the declining costs of energy storage, it appears that the San Francisco approach is not only uniquely qualified to address the unpredictability of earthquakes—but also represents a more sustainable and climate-friendly approach to community resilience.

So far, vendors such as SMA, Tesla, and Saft have been involved in the modeling of these systems to be installed in the coming years. While a program with the noble goal of emergency response, the community resilience microgrid market also represents an economic opportunity. Under a base scenario, the market is projected to reach $1.4 billion globally by 2024.

 

High Resolution Sensors Open New Windows onto the Grid

— March 26, 2015

The advances in transmission and distribution (T&D) system sensors, communications, and visualization technology are remarkable. At DistribuTECH 2015, I was able to talk to key vendors in the T&D marketplace, including established players, such as ABB, GE, Landis & Gyr, Schweitzer Engineering Laboratories (SEL), and Siemens, as well as emerging companies, such as Genscape on the transmission grid and Tollgrade on the distribution grid, which both offer innovative new monitoring and visualization solutions. These relatively young companies are taking the industry to a next level in sensor technology, wireless communications, and visualization/analytic tools.

While Genscape is a new entrant in the transmission operator/utility marketplace, it operates the world’s largest private network of in-the-field monitors, providing cloud based software as a service (SaaS) applications for market intelligence across the power, oil, natural gas, petrochemical, agriculture, biofuels, and maritime freight sectors. The company’s applications are used by most energy trading companies, and are used to non-intrusively monitor generation plant outputs, outages, and other transmission line conditions.

Unbound

Genscape has a wide range of customers in electric power trading and oil & gas commodity markets.  With the recent acquisition of Promethean Devices in 2014, Genscape also provides high resolution, sub-second transmission line monitoring of current, conductor sag/clearance, conductor temperature, and voltage, using an easy to deploy ground based solar powered sensor system. With the high cost of land-based fiber systems typically installed by utilities, Genscape’s solution offers an elegant and relatively inexpensive cloud-based solution.

Focused primarily on the medium-voltage (MV) and low-voltage (LV) distribution grid, Tollgrade offers bolt-on line sensing units with high speed wireless communications capabilities, as well as a cloud-based SaaS optimization and visualization tool set that can be tied into a utility’s distribution automation system. The company’s fault-detection hardware and predictive analytics software are designed to assist distribution network operators in avoiding network outages and reducing customer downtime. The sensing units are low cost and can be installed by a distribution system lineman in minutes at any location on the distribution system.

The really striking thing about Tollgrade’s technology is the analytics and visualization tools, which can be used to drill down in outage and fault data to screen, locate, and then analyze breaker trips and outages anywhere on the monitored portions of the distribution network in real time.

Both of these companies have the potential to significantly change the level of visibility into T&D grid performance, providing tools for understanding the disturbances that are never seen in the data typically collected by utilities using conventional solutions.

 

In Detroit, a Utility Comes to the Rescue

— January 14, 2015

In early December, the municipal power system in Detroit had a major power outage that was thankfully restored by DTE Energy (DTE), the investor-owned utility that stepped in to lend a helping hand.  The Detroit municipal system supplies power to city buildings such as courthouses, hospitals, city offices, and schools, as well as critical local infrastructure such as traffic lights, municipal transportation, and fire departments.  Even the Detroit Red Wings hockey practices were disrupted by the power outage.  Fortunately, with the help of DTE, the outage was restored within 9 hours and life in Detroit was back to normal.

As news of the municipal power system outage spread, it was initially speculated that this power failure was another glaring example of the lack of ongoing investment in critical infrastructure that occurs when a municipality goes into bankruptcy.   The good news is that, as part of the bankruptcy process, Detroit will no longer run the electric system; DTE will begin running the grid over a 4-year transition period.  DTE’s deeper pockets will restore the high standards of operation for the Detroit municipal system.

The Beleaguered City

Detroit’s woes have been national news over the past 3 or 4 years, as illustrated by the many pictures of abandoned neighborhoods, factories, churches, and commercial buildings.  In fact, Detroit’s mayor, Mike Duggan, said at a news conference on Tuesday, December 2, 2014 that, “Today is another reminder of how much works we still have to do to rebuild this city, and the bankruptcy order doesn’t solve the decades of neglect in our infrastructure.”  The mayor’s spokesperson, Robert Warfield, went on to say that the outages were “caused by extreme heat, cable failure, and routine maintenance – all combining causing system overload.”  Apparently, a cable feeding a critical substation failed, and the municipal utility tried to reroute the system, triggering a circuit breaker, which caused the blackout.

Spirit of Cooperation

During 2014, I wrote a number of blogs on various utility transmission and distribution issues that arise and the investment required to keep the lights on.  These issues are also discussed in detail in Navigant Research reports, including High-Voltage Transmission Systems, Flexible AC Transmission Systems, Synchrophasors and Wide Area Situational Awareness, and Smart Grid: 10 Trends to Watch in 2015.   Over the years, I have seen neighboring and even distant utilities step in to help utilities in another state or region restore power after a natural disaster, storm, or power failure.  DTE’s work to make sure the lights stay on in Detroit is another great example of the spirit of cooperation within the electric utility industry.

 

In Major Storms, Utilities Turn to Technology

— June 6, 2013

According to Oklahoma Gas & Electric’s System Watch web portal, more than 140,000 of its roughly 800,000 customers lost power during the second of two Oklahoma supercell tornados on May 31.

Everyone wonders what is going on in the cockpit when the plane is stuck on the tarmac.  In the modernized utility distribution control center, the operators have complete and current situational awareness of tens to hundreds of distribution circuits (OG&E has 1,100 circuits in its service territory), and sometimes more than a million meters.  Like a pilot in the cockpit, grid operators will have stackable monitors, color coded visualization on a GIS-enhanced interface, and the capability to quickly zoom in on alarms and provide intel to assessor, restoration crew etc.  Several such smart grid functions will have been used and useful in the overall effort of scouting, repairing, and managing outages in Oklahoma over the last 2 weeks.

On April 27, 2011, the resilience of Alabama Power Co. (APC) was tested in the most severe weather incident in the state’s history.  The outbreak of tornados resulted in 239 deaths.  Roughly half of Alabama Power’s 1.4 million customers were without power after more than 3,000 distribution transformers and twice as many poles were downed.  Eight distribution substations were either damaged or destroyed and 400 transmission structures were broken.  Yet, it took only 7 days for the utility to restore power.

The Next Generation

More than 10,000 mutual assistance resources were utilized, meaning restoration crews came from other states to help.  The company took a decentralized and mobile command approach; it used 11 staging areas, each equipped with a distribution management system (DMS) to manage remote switching and other operational control.  During less severe storms, APC operators can turn on an autopilot function (known as fault location, isolation, and service restoration, or FLISR) in the DMS to speed up service restoration, saving thousands of customers from sustained outages every year.  The smart utility’s goal is to minimize customer impacts by reducing restoration time when major events occur.  Utilities are looking to information technology / operational technology (IT/OT) integration and increased mobility to assist with outages.

In the event of outages, utilities rely on operational systems to notify customers of causes and estimated restoration times.  Next-generation DMS will be integrated with outage management to provide additional inputs for visualization and decision support to better address impacted areas.

Advanced workforce management (WFM) solutions that enable utilities to forecast, schedule, dispatch, and monitor progress of outage crew have gained increased interest.  WFM is carried out with the assistance of outage management tools that analyze outage reports to determine the scope of outages and the likely location of problems.  An outage management system (OMS) or a DMS compiles information on the times and locations of customer calls, smart meter outage notifications, and fault data from substations and monitoring devices on feeder lines.

Some utilities are reporting that the integration of advanced metering infrastructure (AMI) has given them the capability to reduce outage time by being able to confirm if meters have power or not.  AMI plays out in two different stages of restoration:

  • After performing restoration work in a given area, service at all the meters can be confirmed quickly and remotely before crews move onto the next area.
  • Individual complaints are followed up on in the wrap-up phase of a large storm restoration effort.

Traditionally there are always a lot of single customer outages that end up being “OK on arrival”, meaning a technician was dispatched with a ticket to restore power only to find out power has already been restored.  By confirming power has been restored via AMI and backing that up with a phone call to the customers, hundreds of truck rolls are saved in large storm events.

 

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