EET&D   : What smart grid upgrades would aid in power outage management during disasters such as Sandy?

  McDonald   : First and foremost, the improvement that utilities must consider is their communications infrastructure. This is the foundation of the grid, as it must be robust enough to support the technologies that are overlaid on top of it.

There are three different facets of the communications infrastructure that utilities should focus on:

1. Response requirements: These ensure that the communications infrastructure can support the smart grid applications’ response needs in a matter of seconds, minutes or hours.
    
2. Bandwidth: Applications send data back and forth, and the infrastructure must be robust enough to support the smart grid applications’ data flow requirements.
    
3. Latency: The delay in communications that the grid infrastructure can tolerate must be satisfactory to the application.

  EET&D   : When analyzing the smart grid during a disaster, what component do you consider to be the most important, and why?

  McDonald   : It’s difficult to pinpoint a single component of the smart grid that is most important, as the integration of all of the separate components (smart meters, AMI, GIS, OMS and DMS) is key when dealing with disasters such as Superstorm Sandy. However, there is a critical part of a utility’s system – the distribution area – or the part of the grid that brings electricity to the customer. The distribution area has historically had the least investment in added technology, which makes it extremely difficult for utilities to detect disturbances. There are 48,000 distribution substations in the U.S., and less than half have any monitoring at all. As smart grid modernization continues, there needs to be an increased focus on the distribution system – and more investment in monitoring and control is critical to more effectively manage power outages during extreme cases such as Sandy.

  EET&D   : What are ‘last gasp’ and self-healing technologies, and how could they benefit utilities and consumers?

  McDonald   : The ‘last gasp’ capability is one that GE has built into smart meter technology. As long as electricity is on, a smart meter can perform its functions and communicate with a utility. When power is lost, ideally the meter would send a signal indicating lost power to the utility. As more than half of the 48,000 distribution substations in the U.S. are without any sort of monitoring capability, there is no way for utilities to tell when power is lost, unless consumers call the utility, which may take hours if it even happens at all. To solve this issue, GE has equipped its smart meters with a stored energy device, called a capacitor, which is charged as long as the meter has electricity. When power is lost, the capacitor has enough charge to allow one ‘last gasp’ communication that travels upstream to the utility indicating a loss of power. This enables utilities to realize which customers are without power, which is a critical first step in mitigating the outage, and also activates self-healing smart grid applications that will restore power to the healthy sections of the grid as quickly as possible.

A typical self-healing technology that’s implemented into distribution systems is a smart grid application called fault detection isolation restoration (FDIR), which detects when there is a fault in the distribution system. The last gasp from the meters informs utilities which customers are without power, while the FDIR application will sense the problem on the distribution line and identify the location, isolate the faulted section by sectionalizing on either side of the disturbance, and restore service to the healthy parts of the grid as quickly as possible, both upstream and downstream from the faulted segment. The utility then sends a crew out to look at the faulted section of feeder, perform any needed repair and bring power back on to faulted segment. The self-healing power aspect of these technologies is that they run “closed loop”, meaning no human is involved. The system essentially heals itself, and because no human is in the loop, it can perform its restoration very quickly.

  EET&D   : Could you provide an example in which the smart grid actually provided outage management during Sandy?

  McDonald   : The Rockefeller Center, or ‘30 Rock’ building, never lost power during Superstorm Sandy. When designing 30 Rock, the planner kept natural disasters and other unpredictable incidents in mind. GE engineers were involved in the design of 30 Rock’s electrical system and installed an uninterruptible power system (UPS), a series of batteries and a diesel generator to ensure power would never be lost. In the case of Sandy, when 30 Rock lost power from the local grid, the UPS and batteries kept power on to the critical loads that were deemed important enough to remain energized during an external outage.

When power outages occur in a massive building such as 30 Rock, the electrical system’s voltage will fluctuate more wildly than it would under normal conditions, because as load is lost and the system is fluctuating, the voltage decreases and oscillates. To keep the electricity on, loads require a constant voltage. A UPS provides constant output voltage, regardless of how much voltage is varying in the input. The installed batteries are sized to withstand multiple hours of power outages, and while the batteries are feeding critical loads, the diesel generator starts automatically. Once synchronized with the electrical system, the diesel generator will take over for the batteries, as the generator can supply power to a facility for as long as there is fuel available. Hospitals, airports, casinos and other “mission critical” facilities where reliability is extremely important utilize these technologies.

  EET&D   : Can you outline the specific technologies that make up an integrated smart grid system?

  McDonald   : If a utility invests in the following four technologies and integrates them in the correct manner, it will be fully prepared for a disturbance, both in proactive preparation and the ability to restore the system following a disturbance.

1. AMI (Advanced Metering Infrastructure): The AMI is a solution in the communications infrastructure that is comprised of a two-way communications system and used in conjunction with smart-metering. This system allows utilities to gauge electricity usage from the meters themselves, while also providing voltage and outage information to utilities. This solution provides utilities with real-time data regarding power consumption and also empowers consumers to make informed choices about energy usage.
    
2. GIS (Geographic Information System): This system, which serves as a reference system for the outage management system (OMS) and distribution management system (DMS), is comprised of two main parts (below). These two parts provide the OMS and DMS with the network model of a utility’s grid, which is imperative for these two systems to function.
    
   • Digitized maps of utilities’ service areas: Utilities can see latitudinal and longitudinal coordinates in a digitized map both for a surface area and each of the assets in that surface area, such as wood poles, transformers, circuit breakers and so on.
      
   • Facilities’ management database: For each asset in a service area, utilities have access to a database that provides the geographic coordinates and location of that asset, in addition to significant information about that asset, including the nameplate from manufacturer, maintenance information, cable company equipment, phone company equipment, and utility equipment.
      
3. OMS (Outage Management System): The OMS gauges which pieces of electrical equipment are experiencing failure. The OMS gathers this information from the following sources:
    
   • Phone calls from customers: Fifteen years ago, customer phone calls were the only source of information for an OMS. Utilities had to wait for customers to call in to report outages, if those calls even came in. The OMS’ performance was dependent on how many calls it got. The longer the delay for phone calls, the longer utilities were delayed in correcting power outages.
      
   • SCADA (Supervisory Control and Data Acquisition System) System: Approximately 10 to 15 years ago, the industry began requiring the integration of the SCADA system with the OMS. The SCADA system can immediately detect a change in state on any device on the grid. For example, if there is a fault on the system, the protective characteristics of a circuit breaker will detect the fault as soon as it occurs and will very quickly open to de-energize the line and prevent the disturbance from cascading into something more widespread, like a blackout. Immediately isolating the fault or problem and keeping it localized is key. While utilities still receive phone calls flagging outages, the integration between the SCADA system and OMS allows for a change of state and exchange of information much quicker than previously done.
      
   • Tweets from customers: GE has successfully integrated social media information, such as tweets, as another source of information for the OMS.
      
4. DMS (Distribution Management System): This part of the grid is considered the ‘quarterback’ of the four technologies (AMI, GIS, OMS and DMS), as it is the overall manager of the distribution system. The DMS is made up of two parts: the SCADA system and smart grid applications. The SCADA platform, which provides supervisory control and data acquisition functionality, serves as the foundation on which the smart grid applications overlay. Once the GIS provides the DMS with the grid network typology and configuration, the OMS is then integrated with DMS through the SCADA system. The DMS smart grid applications include FDIR, IVVC (integrated volt/VAR control), Three Phase Unbalanced Load Flow, Optimal Feeder Reconfiguration, and Load Estimator. Additionally, an Energy Management System (EMS) is comprised of the SCADA platform and special applications that deal with the generation and transmission parts of the system, instead of distribution, like the DMS.

  EET&D   : Why do utilities hesitate to implement integrated smart grid systems?

  McDonald   : We have to remind ourselves that utilities operate in a regulated marketplace – any investment that the utility makes is regulated in terms of the return on investment. Additionally, these regulations differ from state to state. In one state, policies may favor investments in smart metering communications, while another state may be more focused on improving the reliability of the distribution system. We must first look at policies and regulations to gauge to what extent a state encourages or supports an investment in a particular application.

Secondly, as previously mentioned, the distribution area of the utility system historically hasn’t received significant investment. The technology for monitoring and control is very cost effective today, and the business case for remote monitoring and control is strong, but more than half of substations in the U.S. haven’t had any sort of investment in automation. The AMI, GIS, OMS and DMS technologies and systems rely on the distribution system, which is imperative for an integrated grid.

Additionally, we must look at the DMS itself. The concept of a separate SCADA system for distribution management is a fairly new concept. Historically, the distribution system has been simple to manage with electricity flowing in one direction from source to load (a radial system), so the need for a separate SCADA system hasn’t been there. Now, with the smart grid integrating renewables and power now flowing in two directions, the system is much more complex. This complexity has recently required utilities to think about a separate SCADA system for distribution, while also integrating the OMS, GIS and DMS together.

Utilities can’t just invest in these technologies – but must integrate them together, which is a new concept. For this to happen, state policies must change to incent and encourage utilities to make these investments.

  EET&D   : Can you further discuss the role of industry standards - compliance and interoperability – with these smart grid solutions?

  McDonald   : The smart grid has emphasized transition from devices and systems to solutions. These solutions are driven by a utility’s business needs, and the set of technology components that make up the solution are put together, typically from different suppliers. The concept of an industry standard forces consistency among multiple suppliers. These multiple components will only interoperate if all of the suppliers comply with the same industry standard and the components have been tested for interoperability.

There are two facets to success. The first is compliance. It ensures that suppliers are correctly implementing the standard. This can be tested by a third-party vendor, who will test compliance and award a certificate following the test if the supplier’s device passes. Secondly, interoperability testing is key. Once the supplier’s device passes the compliance test, there may still remain incompatibilities between separate components. To solve this issue, industry organizations hold events called Plugfests, where equipment suppliers come together to ensure that equipment communicates successfully with equipment from other vendors. If not, suppliers will change the software on the spot and test again. These events ensure that all suppliers’ components are fully interoperable, and that is the only way that smart grid solutions can be successful. As we transition into smart grid implementation, the role of industry standards has become much more important. The smart grid brought us the concept of solutions, which demands an emphasis on standards and compliance and interoperability testing.

  EET&D   : We can’t thank you enough, John, for taking the time out of what I’m sure has been an absolutely hectic schedule. I know our readers will gain a lot of insight from your in-depth knowledge of smart grid. No one would ever want to see a repeat of Hurricane Sandy but it’s reassuring to know that companies like yours are working around the clock at improving the technologies that can improve lives during the aftermath of a major weather event.

About the Interviewee

In his role, John provides the strategic leadership and develops the long term plans to optimize Digital Energy’s competitive position. This is a new and highly visible position and will set and drive the vision that integrates GE’s standards participation, and Digital Energy’s industry organization participation, thought leadership activities, regulatory/ policy participation, education programs and product/systems development into comprehensive solutions for customers.

John received his B.S.E.E. and M.S.E.E. (Power Engineering) degrees from Purdue University, and an M.B.A. (Finance) degree from the University of California-Berkeley. He is Fellow of IEEE, and was awarded the IEEE Millennium Medal in 2000, the IEEE PES (Power & Energy Society) Excellence in Power Distribution Engineering Award in 2002, the IEEE PES Substations Committee Distinguished Service Award in 2003, and the 2009 Outstanding Electrical and Computer Engineer Award from Purdue University. John is the IEEE PES Past President, CIGRE US National Committee (USNC) VP Technical Activities, and IEEE PES Substations Committee Past Chair. John is the Smart Grid Consumer Collaborative (SGCC) Board Chair, and the NIST Smart Grid Interoperability Panel Governing Board Chair.