While energy storage has been dubbed the "holy grail" of grid operators, that notion thrived better when it applied to a vague ideal rather than cold reality.
Today, with long- and short- duration energy storage alternatives to pumped hydro moving from lab to market, the quest has become vastly more complicated and the goal more elusive. Electro-chemical storage (batteries), thermal storage and mechanical storage all have possible roles.
But before utilities invest in any of these technologies, they need to answer whether the technology itself works in the field, which applications are appropriate, whether legitimate business cases can be fulfilled and whether existing alternatives continue to win on a cost-benefit basis.
The holy grail no longer is the technologies themselves. It's whether those technologies meet the aforementioned criteria for deployment within an operational context with a winning cost-benefit ratio.
That's a tall order. The good news is that numerous utilities are involved in pilot projects to determine the answers to these simple but potentially vexing issues. And myriad utilities, currently on the sidelines, need to know how to think about the complexities around energy storage, whether they should be testing the technologies on offer or believing vendor spiels.
To grasp the big picture around these issues, as well as the nitty gritty on how two leading utilities are going about answering these and other pertinent questions, join us on Wed., July 11, at noon EST for "Putting Energy Storage Into Action," a webcast that will feature Mark Irwin, director of technology advancement at Southern California Edison (SCE), and Chris Rees, strategic planning manager at Duke Energy.
(Click on the webcast title to reach the registration page.)
The pace of registrations reflects intense interest in this topic and I look forward to having as many readers onboard as possible. Let me remind everyone that both speakers will offer a concise overview of the many strands of each of their projects and that audience questions of widest relevance will be conveyed live to our presenters.
I spoke recently with both Irwin and Rees to find out what they're doing and where the lessons learned might be this early in the quest to answer many inter-related and decidedly complex issues around energy storage on the grid.
"Straight Talk on Energy Storage" described Southern California Edison's philosophical approach to energy storage. I'd recommend perusing it and following the link to the SCE paper.
SCE's Tehachapi wind generation site offered a number of characteristics, challenges and opportunities that made it the site for this demonstration project, expected to show results in 2013.
"We have 13 different use cases we're going to test," Irwin told me. "First, of course, does the device do what it's supposed to do? We're really going to test, from a business case standpoint, how we need to trade off these applications. Because, obviously, energy storage can't do all of them simultaneously."
I pointed out that SCE's approach seems to be that if the same energy storage facility can serve multiple applications, producing multiple value streams, it begins to make sense in a business case.
"Another way to think about it," Irwin clarified, "is that you could serve multiple business cases and give up some portion of that value for each application alone. But you don't sacrifice a lot of that value."
If SCE can capture a high proportion of the value of multiple applications, it may have a business case for energy storage, Irwin said.
Dubbed the "Irvine Smart Grid Demo Project," the SCE effort has eight sub-projects. The storage facility, consisting of lithium-ion batteries, comes in four units and 16 installations. One battery is for integrating photovoltaics, one battery is dedicated to a distribution transformer (serving as a form of community energy storage), another (portable) battery will sit on the distribution feeder, and one will be connected to a car shade over a parking garage (to avoid creating an electric vehicle charging peak while hitting the day's peak load).
One overriding driver of interest to SCE: improving overall system reliability.
In our webcast, Irwin will share insights into SCE's drivers and project details as well as the philosophy cited earlier that governs its thinking as it approaches these tasks.
According to Rees, Duke Energy's battery storage project will test the economic viability of energy storage. That means seeking the new holy grail: a business case for it. Duke's site at the Notrees wind site in West Texas focuses on lead-acid batteries.
The most effective application appears to be the frequency regulation market in ERCOT, the Electric Reliability Council of Texas, which needs several hundred megawatts each hour to maintain the grid's frequency at 60 hertz. This need has increased with an increased proportion of variable output renewable energy providing generation.
"Wind variability means the output of a wind farm changes quickly," Rees told me. "In 30-40 minutes, it can range from zero to full output."
With that sort of fluctuation across the grid, utilities need a resource to mitigate it. Today, that's typically achieved with combustion turbines fueled by natural gas, which can provide hundreds of megawatts, Rees said.
Energy storage in the form of lead-acid batteries is quicker than steam-driven power; it ramps from full charge to full discharge in less than a minute. With faster response to regulation signals, it is hoped that the need for regulation capacity can be reduced.So, with the DOE grant, a lead-acid battery alternative to natural gas-driven CTs is being explored.
In our webcast this Wednesday, Rees will provide an overview of the project, discuss the configurations being tested and provide a timeline for results that can be shared with the industry. He'll also discuss working with ERCOT on its market rules for frequency regulation, as well as regulatory issues for utilities in other markets.
Please join us.
Intelligent Utility Daily