DistribuTECH 2016: Increasingly at home with DERs, utilities shift focus to controlling them on the grid
The big question for utilities in 2016 isn’t whether they will be able to integrate DERs — it’s how they will be able to manage them all on the grid
Utilities in 2016 are becoming increasingly comfortable with a tectonic shift in their operational models.
During the last century, utilities operated their grids from the power plant to the customer's meter, distributing one-way power flows as the sole providers of electricity in their service areas.
But in the 21st century, new distributed energy technologies are breaking down the paradigm of the “natural monopoly." The introduction of new customer-sited generation and storage technologies require a grid capable of managing two-way power flows and integrating high levels of intermittent resources in real time.
But despite the challenges that distributed energy resources (DERS) present, utilities are learning to embrace them, finding new products and technologies to enhance customer choice, bolster grid reliability, and defer or avoid costly infrastructure investments.
But as utilities become more at home with an increasing number and variety of DERs on their grids, a new challenge is presenting itself: how to see and control all of the new assets being added to the grid. As industry executives met this week in Orlando at the DistribuTECH 2016 conference, the growing need for a unified control system lurked behind conversations about the breakneck speed of DER growth in many markets throughout the nation.
“Whether it’s a distributed system whereby you’ve got more edge intelligence, or whether it all comes back centrally, some of that architecture needs to be worked out,” Scott Bordenkircher, head of technology innovation and integration at Arizona Public Service told Utility Dive earlier this week. “But you’re definitely going to need a system, because you’re not going to have an operator sitting there 24/7 trying to control several hundred random things on the grid.”
Bordenkircher’s comment came in the context of Arizona’s high rooftop solar penetration and APS’s interest in storage and microgrid pilots, but the theme applies to the sector at large as well. For some utilities, one of the biggest impediments to the long-term growth of DERs on their systems is the absence of adequate communications and control software for the resources.
Oncor: Storage management wanted
In November 2014, Texas utility Oncor sent waves through the power sector when it released a report with the Brattle Group estimating that more than 5 GW (15 GWh) of energy storage could be made cost-effective on the ERCOT grid by the year 2020.
Transmission and distribution utilities like Oncor are prohibited from owning generation in ERCOT, and market rules stipulate storage as one of those assets. So while Oncor can deploy storage for reliability purposes, it cannot use those facilities for market services such as frequency response.
After a push to change those rules failed in the Texas legislature last year, Oncor directed its attention back to its grid optimization efforts while it prepares for the next legislative session in 2017. This past summer, it unveiled a microgrid at one of its operating facilities near Lancaster, Texas, combining solar, storage and a diesel microturbine in an attempt to eliminate outages at the facility.
Through that microgrid and other storage pilot projects, Oncor found that “the control systems are much more the issue than the batteries themselves,” said David Treichler, director of business development at the utility. “If you can’t find control systems to operate these things economically, and appropriately, you’re not going to be able to manage the system.”
The Brattle report on Texas storage estimated that Oncor could have as many as 25,000 independent batteries operating in its service territory in the coming years, Treichler said, “so a control system that operates that complexity was an essential aspect of what we were concerned with.”
“Much of the research developments and technology efforts that we’ve had have been meeting with various vendors trying to determine who really is on a path to build the kind of control systems that will be essential,” he continued.
Oncor designed its latest microgrid to deliberately integrate 35 different vendors into one system. The result was a challenging project from an operational standpoint, but it led to a lot of institutional learning.
“We could have gone out to ABB and said, 'Give us a microgrid,' but we wouldn't learn anything by doing that,” Treichler said. “We have learned a lot by putting 35 different vendors in one spot because that’s the reality of what the grid is going to be, and Oncor’s whole approach to this process to date has been, ‘What can we learn before we have to do this for our customers?’”
SCE: Achieving a huge storage mandate
To the west of Oncor’s service area, Southern California Edison is facing similar issues as it attempts to comply with the nation’s first and largest energy storage mandate.
In 2013, the CPUC approved a mandate for its investor-owned utilities to deploy 1.3 GW of energy storage (excluding bulk storage) by the end of the decade, split evenly between utility and third-party ownership. The order stipulated that the utilities contract for 50 MW of storage by the end of 2014, but the storage proposals competed so well against renewables and natural gas that SCE announced contracts for 264 MW of stoarge in November of that year.
Those distribution-level contracts were all for storage owned by third parties, and SCE is focusing its utility-owned storage efforts on larger-scale offerings since the RFO process can take too long for distribution circuit needs. Even so, the utility has deployed its own utility-owned storage on a distribution circuit and “expects to deploy a few more in the next couple of years,” according to Mark Irwin, director of technology development at the SCE.
Making storage cost-effective, even in states like California with high electricity prices, usually involves “stacking” the benefits of storage — allowing a battery deployed for reliability purposes to provide grid services when not being used by the customer, for example.
But according to Irwin, SCE can’t perform those market functions with the batteries it has on the distribution system because “we do not yet have the communication and control capabilities in place.”
Typically, using storage for multiple functions means that an operator must know when it is in use for its primary function — such as backup power — and when its capacity can be used for grid services. When the end user is the one bidding the storage into the open market, as can be the case with some third-party owned systems, visibility is less of an issue. But if a utility wants to use the batteries that provide backup power to a given facility for grid services, it must first be able to tell if it is in use for its primary function first.
“We still have a ways to go there,” Irwin said. “It will be a number of years, but that’s our vision.”
Managing DERs for reliability's sake
The ability to control various DERs on the utility distribution system is important for utilities looking to put new storage technologies onto the grid, but as DER penetration increases across the nation, these communication and control systems could become essential for grid reliability.
Pacific Gas and Electric, SCE’s neighbor to the north, isn’t at the point yet where DERs are causing serious reliability issues, said Kevin Dasso, senior director of technology and information strategy at the utility. The resources are “fairly dispersed around our service area, so we’ve been able to manage through our normal engineering.”
“However,” he said, “we are starting to see some feeders with backfeeds and some of those types of challenges, so one of the areas we’re focusing on is how we can really automate, self-heal, and get more information.”
Central for PG&E, which has more customers with rooftop solar than any other utility in the nation, is finding a system that can collect information on individual solar system output, package it up and show it to the utility in a way that makes sense.
“Some of the core capabilities are understanding really what’s happening on the distribution network,” Dasso said. “There’s a lot of information in the substation — pushing that technology further out [onto the distribution grid], whether its sensing or using smart meter data.”
Once utilities have the capability to see and understand what’s going on, they can work with vendors to design products that allow them to better control various DERs on the grid.
"Ultimately it is about visibility — understanding what’s happening on the network — and control that is more automated," Dasso said. "It’s not going to be an operator sitting with a big dial at every customer’s solar panel, so leveraging those, developing those techs and those capabilities, [will be crucial].”
‘The innovator’s dilemma’: Designing better control systems
If utilities at DistribuTECH this year are largely in agreement that they need better communication and control systems for DERs, just how to get them is less clear.
“I think there’s two legs to that,” SCE’s Irwin said. “One leg is vendors having that product and the other leg is utilities implementing that product, and before we implement that product we want to see that it works properly.”
That observation — that utilities may be apprehensive to go out on a limb with a new control system — was echoed by Oncor’s Treichler.
“It’s the simple innovator’s dilemma,” he said. “You come up with a new approach, [but] you've got to get it used by somebody before people will rely on it.”
“We all know in the utility industry there are very few bold tech executives,” he added. “Those who go out there first usually find an arrow in their back, so we’re waiting for somebody to step out there first, and then Oncor is going to be there fairly close to the front.”
A few companies appear to be stepping to the fore. Last month, the Department of Energy unveiled $18 million in funding for its Sustainable and Holistic Integration of Energy Storage and Solar PV (SHINES) program, which aims to provide funding for utilities and vendors collaborating on next-generation control systems for distributed resources. Included in the grants are awards to Austin Energy, Commonwealth Edison and Hawaiian Electric, as well as money for research and academic institutions.
In addition to those early movers, Irwin said that SCE will soon begin testing control systems of its own.
“I think we will see demonstration projects in our company in the near term that start demonstrating the capability of the product ... to integrate DERs,” Irwin said. “Our current plan is [to have one operational] either in 2018 or 2019.”
For the time being, Oncor will continue studying its microgrid control system and talking with other utilities and vendors about their best practices for distribution system control.
“We’re out gathering data... trying to answer questions about this and trying to make the case for regulators and legislators that [storage] is in fact a technology that has arrived,” Treichler said.
But the utility industry is on a timetable, he added. Many analysts, including those who put together Oncor’s Brattle report, expect that many storage technologies will hit widespread cost-effectiveness on the grid somewhere around 2020, which could spark massive proliferation of the resource.
“Four years from now, in 2020, is when everyone thinks everything is going to change with battery storage, so we have four years to get systems out there, gather the data, publish the reports to let people know what's going on,” he said. “We’re trying to learn the lessons without penalizing our ratepayers in the process… and hopefully other utilities take a similar approach.”
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