Utilities Try Microgrids as Major Option
By Rod Walton, Senior Editor
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| National Renewable Energy Laboratory (NREL) engineer Andy Hoke replaces a sensor on a solar array. Solar PV is an integral part of many microgrids. (Photo courtesy: NREL) |
No man or woman is an island, but their neighborhood might be someday soon.
This is not about John Donne metaphors or worries about rising seas. This is about both the dangers and possibilities of microgrids, those isolated power systems that are growing in numbers and durability every year due to falling costs of distributed energy generation and increasing knowledge of how to keep those sources safe and under control.
Major players such as Oncor Electric Delivery, Duke Energy, Schneider Electric and ERDF are investing big in microgrid pilot projects that can involve small pockets of residential, public service or industrial districts. Some are not so little anymore, such as Schneider Electric’s plan to build a microgrid at its Boston One headquarters campus by this fall. REC Solar will build and operate the microgrid that will include a 400-kW rooftop solar photovoltaic (PV) system generating about 560,000 kWh per year and saving the company nearly 5 percent on electricity costs.
In some situations microgrids are more of necessity than a trendy option. Some are constructed to feed remote military bases and communities or to provide power to poorer regions, such as in Haiti, which have less access to a power grid. They exist because they fit the need.
Microgrid proponents domestically see their projects as environmentally friendly ways to disconnect from the grid, as well as take some load off the main systems. Figuring out the right combination of renewables, energy battery storage and backup generation is part of the challenges some like Schneider, Duke and Oncor are willing to tackle. In their opinions, microgrids are coming so utilities should embrace them.
“Some see it as unsettling working with microgrids,” Andrew Bennett, Schneider’s senior vice president of U.S. energy business, said at a February executive briefing during DistribuTECH week in Orlando. “We don’t have those apprehensions.”
Bennett went on to say that “unparalleled” amounts of capital are flowing into microgrid investment, and the statistics seem to back him up. Reports by Navigant Research indicate that microgrids could generate $20 billion in annual revenue globally by 2020, while installations could increase five-fold during that same period.
Distributed generation (DG) sources, mainly solar PV, are game changers for the electricity industry. They pose a great risk-reward ratio; the latter is a boon for solar PV, energy storage and control-system firms, but the former is the unknown of disconnecting from the main grid and how easily it can be reconnected safely.
Islanding is one great danger for those who work on the power lines around distributed generation. A grid can be disconnected but a DG system potentially can create a surge from the home end of the meter. Experts have noted that islanding is one of the barriers and relative unknowns in microgrid implementation.
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| NREL and Raytheon perform system level testing on the Miramar ZnBr Flow Battery Simulated MicroGrid, in the Energy Storage Lab at the Energy Systems Integration Facility (ESIF). (Photo courtesy: NREL) |
The new frontier of microgrids can turn islanding on its end, making it an objective rather than an accident. Projects such as Duke Energy’s McAlpine Microgrid in North Carolina, Oncor’s Technology, Demonstration and Education Center in Texas and the NICE GRID in France are experimenting with how to island their systems safely for as long as possible.
“This spring we plan to island…watch the fire station operate on solar and battery as long as it can,” said Tom Fenimore, Duke Energy’s manager in develop of emerging technologies, about the McAlpine project, which created a microgrid serving Fire Station 24 in Charlotte, N.C. “We want to understand how long we can depend on this thing.”
Duke is gaining bountiful information from its go-round at McAlpine, but it and other players can also look across the pond, so to speak, to see the cutting edge in islanding experimentation. The NICE GRID in Nice and Carros, France, is a system serving 2,500 smart meters with solar PV and battery technology from Saft, which can store 560 kWh.
Microgrid FAQ
What is a microgrid?
A microgrid is a local energy grid with control capability, which means it can disconnect from the traditional grid and operate autonomously.
How does it work?
A microgrid generally operates while connected to the main power grid, but importantly, it can break off and operate on its own using local energy generation in times of crisis like storms or power outages, or for other reasons. A microgrid can be powered by distributed generators, batteries, or renewable resources like solar panels or a combination of these. Depending on how it’s fueled and how its requirements are managed, a microgrid might run indefinitely.
How does a microgrid connect to the main grid?
A microgrid connects to the grid at a point of common coupling that maintains voltage at the same level as the main grid unless there is some sort of problem on the grid or other reason to disconnect. A switch can separate the microgrid from the main grid automatically or manually, and it then functions as an island.
Why choose a microgrid?
A microgrid not only provides backup for the grid in case of emergencies, but also can be used to cut costs, or connect to a local resource that is too small or unreliable for traditional grid use. A microgrid allows communities to be more energy independent and, in some cases, more environmentally friendly.
How much power?
A microgrid can power a single facility like the Santa Rita Jail in Dublin, California, and Duke Energy’s microgrid around a fire station in Charlotte, North Carolina. It also can be designed for bigger loads, such as the Niobrara Energy Park in Colorado, which was planned to incorporate several energy sources totaling hundreds of MWs.
Source: U.S. Department of Energy
Thomas Drizard, project engineer with French distribution manager ERDF, said a joint venture with control-systems firm SOCOMEC achieved a world-record islanding event of five hours on Oct. 6, 2015.
“The storage assets adapted the schedule to allow for five-hour islands,” Drizard said during his presentation at DistribuTECH. “The power converter system ensured a good quality of supply during islands.”
A conference session at DistribuTECH in Orlando, titled “DER and Microgrids Integration: Now and in the Future,” focused on Oncor Electric Delivery’s fledgling microgrid in Lancaster, Texas. The Technology, Demonstration and Education Center (TDEC), as the Oncor microgrid is known, began with groundbreaking on Aug. 13, 2014 and went “live” by March 2015.
“We went from initiation to construction in nine months,” Larry Kohrmann, Oncor’s senior distribution operations manager, said. “I would not recommend that.”
Kohrmann’s line got laughs in the otherwise sober presentation, but the point was clear: Microgrids need ample time to plan, coordinate and operate. Oncor partnered with Schneider Electric and S&C Electric on various components, although the 100-acre site was owned and controlled completely by the utility. The various power sources included: a 200-kW battery with 400 kWh in energy storage, 104 kW in solar PV facing south and 2 kW in solar PV facing west. Finally it was rounded out with a 65-kW “microturbine” fueled by propane, although the site also kept 550 kW in diesel genset capability for emergency purposes.
The system was designed specifically to operate without grid power, or islanding, and to fail-over to a blackstart sequence upon loss of grid power, Kohrmann said in an email exchange with POWERGRID International. Lessons surely were learned in this experiment by Oncor, company officials said, although some challenges could not be anticipated but only revealed through trial and error.
“The lack of a full understanding of the performance needs vs. capabilities of legacy equipment, and performance needs vs. understanding specifications in new equipment,” Kohrmann said were about the biggest problems TDEC microgrid faced. “This is an institutional learning process. What was learned can make future projects more straightforward.”
Indeed, future projects are a virtual certainty when it comes to Oncor and numerous other utility and service companies. The proliferation of distributed energy resources makes the microgrid a considerable option.
“Today, there is a statewide dialogue about how Texas should use this game-changing technology for the future grid,” Bill Muston, Oncor’s manager of research and development, said. “Microgrid capability is a necessary part of the future grid. Viability will improve as control systems mature, and as the costs of energy storage equipment decline.”
Renewables integration, of course, is the engine behind all of this. Bi-directional flow of electricity is a risk both to the grid and people who work on it. Utilities and their vendors are working hard to develop best practices that will make this future grid safer. Battery systems are the anchors of microgrids, Kohrmann said. But control systems and smart inverters, among other things, are needed to integrate the distributed generation.
Masaru Natsu, Pacific Gas & Electric’s (PG&E’s) emerging technology engineer, spoke at DistribuTECH as part of the “Utility Experiences with PV Integration” session. California altogether has about a quarter of solar installations nationwide, and PG&E specifically deals with a new PV customer about every 11 minutes, or 4,200 installations each month, he said.
The utility engaged with a smart inverter working group to develop and maintain top-end communication standards, Natsu said.
Jovan Bebic, a managing director of GE Energy Consulting, pointed out the risk of unintended islanding if PV inverters don’t communicate within the distribution applications of the grid.
Natsu backed up Bebic’s viewpoint.
“Utilities need to communicate to DER (distributed energy resources) systems, to facility energy management systems to aggregators,” he said. “It seems quite easy, but in the end you’re talking about communicating with third parties.”
Standards and protocols need to match up across the board so utilities and vendors are on the same page, Natsu and Bebic said. Once those best practices are agreed upon, it’s all about product development and real-world testing.
GE and PG&E worked on testing to understand how DER behaves on the grid. They studied three load zones, 557 feeders, 1,396 reclosers, 14,821 PV sites and, all told, nearly 540,000 load points. They isolated sections and analyzed by circuits. They learned that islands had higher durations when and where there was higher PV penetration.
Forty percent of U.S. energy professionals cited in a recent “Utility of the Future” survey indicated that increased interconnection of distributed generation was the most significant challenge of the next five years. Pay attention to what is happening in Hawaii, where solar PV penetration is rushing toward the market norm, said Julio Romero Aguero, a DistribuTECH session chair and vice president for strategy and business innovation at Quanta Technology LLC.
“Look at the performance of PV in Germany” where current PV power is about 24.9 GW, he added. “That’s really impressive. Are we heading in that direction? We may be.”
Microgrids likely will be the gathering and control point for PV’s headlong rush into the limelight, some say. And utilities are wise to figure out ways to make it all work together, Oncor’s Muston advised.
“Many forms of microgrids will occur, and not be identical,” he said. “Utilities will find uses for microgrid capabilities for deferring traditional asset upgrades, for local reliability support and for integration and management of distributed resources, whether solar PV or dispatchable generation.”
Editor’s note: To learn more about Oncor’s Technology, Demonstration and Education Center, view a video at bit.ly/1pgx5cd.
