Integrating Distributed Generation into the Smarter Grid
By Gene Zimon
Renewables and distributed generation are here to stay. Grid operators should recognize that distributed supplies must be treated like any other supply source and be fully integrated into transmission and distribution network operations systems. Already there are innovative and cost-effective solutions that are designed to solve or mitigate the problem.
Historically electricity flowed in one direction and the problem for grid operators was ensuring sufficient supply to meet demand. Now, with energy consumers increasingly becoming energy producers, grid operators have to be aware of current and forecasted distributed energy production and distribution.
Utility load control systems currently forecast how much energy to purchase based on prior period usage adjusted for forecasted weather conditions. With growing reliance on distributed energy resources (DER), they now have to forecast their electricity production, local usage and power fed back to the grid. In addition, grid operators must not only understand the current state of the transmission and distribution network, but must also consider the condition of distributed energy plants and the transmission lines to their grid interconnection points.
This is an immediate problem that many progressive utilities are attempting to address. Currently 37 states have Renewable Portfolio Standards (RPS), a driving force for the growth in distributed generation. According to the U.S. Energy Information Administration, as of June 2013, renewables, excluding hydro, accounted for 6.71 percent of American electricity generation; the distributed generation share is significantly larger if combined heat and power, and non-central natural gas fired generators, are included.
Solar, wind and other distributed generation plants are typically situated in remote areas, requiring the construction of new transmission lines to connect to the grid. The integration of the physical flow of electricity from distributed energy units is being addressed through state-enacted interconnect standards (notably, in Virginia, Maine and Utah). Thirty states have comprehensive standards assigning the responsibility and the cost of the interconnection to power producers and ensuring that specific technical and safety measures are put in place. Most of the state standards are implementing IEEE 1547, which requires that any distributed site go offline within two seconds of detecting a power outage on the grid. This is typically done by protective relays internal to the generating facility or by a direct transfer trip signal from the substation.
Solutions for protection and islanding currently on the market are costly and can negatively affect the return on investment of building a distributed generation facility that is compliant with state interconnect standards. Lower cost solutions that meet the IEEE standard should be explored. An example is Northeast Utilities’ pilot, which uses a broadband over power line product (B-PLC) from GridEdge Network to provide protection and isolation on the line between the distributed facility and the grid’s interconnecting point. The system also alerts the utility when a unit is down.
Utilities are also developing solutions that integrate information flows between the utility and the distributed generation plants. Complementary to the physical integration of distributed generation into the grid is the need to maintain a two-way flow of information between distributed facilities and the utility’s SCADA, EMS and load forecasting systems.
The SCADA system requires a real time view of the current and projected flow of electricity throughout the grid. With increasing deployment of distributed resources, access to the condition of a unit and to its current and projected production and distribution is necessary to maintain the reliability of the grid.
Similarly, load management and forecasting systems estimate how much supply to bring in on a daily basis. Without knowledge of current production or forecasts of distributed energy production, the total day-ahead load supplied to wholesale purchasers could have an increasingly widening margin of error as distributed capacity increases. This will increase the wholesale cost of energy, as overestimated base load will result in purchasing too much energy and underestimated base load will require more reliance on spot market purchases.
Unfortunately solutions for data communications from distributed generation plants located in remote areas are difficult to justify since conventional communication mechanisms such as fiber, dedicated telephone lines and microwave links are costly. Given that data throughput will be low, utilities should explore cost-effective alternatives such as wireless and B-PLC technologies to transfer information from the distributed site to the substation. Given that the site has to be connected physically, why not leverage the power lines as the information transfer mechanism?
Fortunately, software vendors such as Draker and Locus Energy are deploying products that not only manage solar performance and asset conditions, but also predict production, measure actual production and control energy flows back to the grid. Both companies have the capability to provide this information in real time to the utility SCADA systems.
The bottom line is that renewables and distributed generation are here to stay. Their production is likely to double every ten years, on conservative estimates. Grid operators should recognize that this supply must be treated as any other supply source and be fully integrated into their transmission and distribution network operations systems. Rather than apply existing solutions to a new problem, utilities should look for innovative and cost-effective solutions that are designed to solve or mitigate the problem.
Gene Zimon is the founder and president of EDGE Advisers, which is focused on assisting early stage companies accelerate the introduction of new technologies into the marketplace. Edge Advisers has done consulting work for GridEdge Network, Draker and Locus Energy. Zimon has had a 35-year career in information technology. From 2001 to 2009, he was senior vice president and chief information officer of NSTAR, a large electric utility in Boston. Before that he was vice president for IT at Boston Gas and vice president of business development for Oracle Utilities. He also held senior IT positions at Wang Laboratories and the U.S. Department of Labor. He earned a bachelor’s degree in economics at Tufts University and amaster's in economics from Boston University.