Utilities face a massive technical challenge in integrating distributed energy resources like rooftop solar, behind-the-meter batteries and EV chargers into their power grids — including setting the common standards for how to get there. One of the biggest stumbling blocks to early DER-grid integration pilot projects has been the lack of well-defined standards for how to manage the operating characteristics and capabilities of energy storage systems, smart inverters and other devices that aren’t part of the traditional utility toolbox.
That’s why many of these pilot projects underway in California, Hawaii, Arizona and other solar-rich states are being matched with efforts to fine-tune and finalize the key standards involved, so that device makers can start building and testing their equipment to support them. California’s Rule 21, which required all new solar installations to support automated smart inverter functionality starting last year, and will require support of utility communications starting in August 2019, is the primary driver for companies in the market today.
But the same set of standards — namely, IEEE 1547 for inverter-to-grid interconnection and interoperability, IEEE 2030.5 for DER-to-utility communications, and DNP3 for utility SCADA networks in the United States — are also likely to serve as the foundations for future utility efforts across the country. At least that’s the view of the utility-funded Electric Power Research Institute (EPRI), which has taken the lead on much of this standards development work in the U.S.
Those include two California Energy Commission-funded projects that have yielded some useful tools for the industry this year: free open-source communications software to support the IEEE 1547-to-2030.5 interoperability to be required of all solar inverters in California starting this summer, and an “application note” that will now be mandatory for utilities using DNP3-based SCADA networks to comply with IEEE 1547.
Both of these tools are now in use by utilities and companies in California, said Ben Ealey, information and communications technology senior projects manager at EPRI, in an interview last week. But “by making this implementation capability available, you can also meet the IEEE 1547 requirements that will be the interconnection standards for many utilities,” he noted, most likely starting with the states with mandates for more distributed energy resources, and the communications and integration needs that will come with them.
Open-source software to get smart inverters to ‘speak’ in smart energy protocol
The first tool, EPRI’s communications software for implementing IEEE 2030.5, was made available last month under an open-source license, as well as to be “freely downloaded to assist with interoperability” — a requirement of the CEC grant that launched the project, Ealey noted. But it’s also built in partnership with some key standards groups and companies involved in 2030.5, including the SunSpec Alliance standards group, microinverter maker Enphase Energy, testing vendor QualityLogic, and Xanthus Consulting, the prime consultant for California’s Smart Inverter Working Group.
IEEE 2030.5 is the standard formerly known as Smart Energy Profile 2.0, the modern replacement for the ill-fated SEP 1.0 technology embedded in the first generation of U.S. smart meter deployments. California made 2030.5 the mandated protocol for all new utility-DER communications in 2016, boosting work on defining the core capabilities needed to enlist DERs as grid agents, such as being able to receive pricing signals or power-down requests and telling the utility what they’ve done in response.
In 2018, QualityLogic released the first “DER Version” of its 2030.5 test tools, including support for solar, storage and EVs in vehicle-to-grid applications. But as with most new standards implementations, mistakes and misunderstandings can stymie the smooth integration of devices from different vendors, even if they’ve complied with the standards to the best of their ability, Ealey said.
Smart inverter pilots being run by California utilities Pacific Gas & Electric and Southern California Edison have encountered these kinds of problems, including one example from PG&E in which two behind-the-meter battery vendors set their systems to respond differently to the same utility signal. Research from the National Renewable Energy Laboratory (NREL) indicates that many of the country’s leading DER integration projects have struggled with similar integration challenges.
IEEE 2030.5 also allows utilities and third-party DER aggregators to interact through the variety of options made available via modern information and communications technology, such as direct utility-to-aggregator cloud integration, or sharing the same data across home internet, cellular and smart meter networks. But this can open up another opportunity for utilities and aggregators to mismatch their implementations of the new standard, and has been a widespread challenge in many of California’s earliest DER integration pilots, NREL noted.
At the same time, the standard hasn’t yet evolved to cover all of the uses that utilities and vendors might envision for it. PG&E’s pilot project to test a distributed energy resource management system, for example, was forced to build extensions to IEEE 2030.5 to handle use cases that weren’t designed into the standard yet, such as bidding DERs into a test-scale distribution capacity market.
The opportunity for mistakes is compounded when one standard is brought into compliance with another one. In order to meet California law, new inverters will have to be able to communicate in a standard way about the “support functions that allow safety and reliability to the grid,” said Ajit Renjit, EPRI’s principal investigator on the project.
These functions, such as injecting or absorbing reactive power to balance local grid voltage, have been built into the “vocabulary” of IEEE 2030.5, in advance of California’s mandate for new inverters to be communications-enabled starting in August. "This implementation will set the stage to meet the critical requirements, and vendors can work on the translation," he said.
Ealey noted that California is only requiring that new solar inverters be communications-capable starting this year, not that they’ll need to be actively communicating with utilities. Turning on more active utility-to-smart-inverter data monitoring, remote connection-disconnection and maximum power controls will come in later years. But they’ll still need to comply with IEEE 2030.5’s latest security and encryption requirements, which is a key concern for utilities contemplating the risks of a system that could be controlling thousands of potentially disruptive DERs in future years.
As for how it’s being put to use, “we’re seeing a number of vendors downloading it and using it in their platforms,” Renjit said. That includes Enphase, which tested the software on its “software-defined inverter platform” at its Petaluma, Calif. headquarters, and declared it a “convenient path to integrating communications, security infrastructure, and messaging support for certification,” according to company co-founder and Chief Products Officer Raghu Belur.
Updating SCADA to support smart inverters and other DERs
EPRI’s second recent contribution to DER integration efforts came as part of a consortium that in January released an “application note” for DNP3, meant to allow the SCADA network protocol to communicate with DERs in ways that comply with IEEE 1547 and California Rule 21.
The product of a partnership with the DNP Users Group, MESA Standards Alliance, SunSpec Alliance, EnerNex and Xanthus Consulting, it’s specifically aimed at filling some key gaps in DNP3’s capabilities to monitor, understand and control energy storage systems, Ealey said.
Because of energy storage’s novelty as a SCADA-connected asset, “every time a new site went out, the utility and everyone building the site had to work on a custom set of information exchanges between the utility and that site,” he said. “If you think about having to develop one of these for each of these systems, it’s going to be very time-consuming,” something the application note is meant to solve.
The lack of common definitions can also yield the same kind of misunderstanding of terms between parties that EPRI’s communications software is meant to avoid in the smart inverter space. For example, “one of the big ones we found was on storage systems, there are two ways to define state of charge, depending on who you are,” he said.
“If you’re managing the battery itself, you want to know where the state of charge is chemically — and you might not want to discharge beyond a certain point, to manage the lifetime cost. But if you’re a utility operator, you also want to know how much is available to dispatch to the grid, or to absorb from the grid,” beyond the electrochemically optimal state-of-charge parameters.
“At one of our meetings, we realized we weren’t talking about the same parameter,” he said. That realization led to the creation of the terms “actual” versus “usable” state of charge to differentiate the two different views, as well as terms such as maximum and minimum usable state of charge and reserve percentage figures, that are now part of the DNP3 lexicon.
Ealey noted that the DNP3 application note must be taken up by utilities and grid operators if they want to remain compliant with IEEE 1547, assuring its revisions will be taken up as utilities adopt the standard.
At the same time, SunSpec is developing a testing framework for solar and storage system implementation of the application note, and the Modular Energy Storage Architecture Alliance is updating its framework for exchanging utility-scale energy storage system data to support the newly defined functions.
This kind of work will become increasingly important as DERs continue to proliferate at their expected rate, particularly in high-growth states like California, Ealey said. “That’s where you see the real benefit of standardizing the data model.”