Black & Veatch has been selected to serve as owners’ representative for an energy storage facility at the San Vicente Reservoir near Lakeside in San Diego County, California.

The project owners, the San Diego County Water Authority and the City of San Diego, are assessing the potential to develop the 500 MW San Vicente Energy Storage Facility (SVESF) to increase the availability and efficiency of renewable energy for the region. It will provide enough stored energy to supply approximately 325,000 homes annually.

As the owners’ representative, Black & Veatch will help evaluate proposals, select the full service team and negotiate the project delivery agreement.

The SVESF will store energy by pumping water to an upper reservoir when energy demand is low and releasing water from the upper reservoir through turbines when energy demand is high.

The pumped-storage hydro energy storage solution would support power grid operations and enable significant and sustained integration of renewable wind and solar energy into the power supply mix. The SVESF would also generate revenue that could help reduce upward pressure on water rates driven by aging infrastructure.

The SVESF project includes the establishment of a small reservoir above the existing San Vicente Reservoir as well as a tunnel system and underground powerhouse to connect the two reservoirs. The powerhouse would contain reversible pump-turbines that would lift water to the upper reservoir or generate energy as it flows down.

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AES India, a unit of The AES Corp., and Mitsubishi Corp. started construction on India’s first utility-scale energy storage system, a 10 MW solution that will serve the electric grid operated by Tata Power Delhi Distribution Limited (Tata Power-DDL).

AES and Mitsubishi will own the Advancion storage solution, which is being supplied by Fluence. The solution is being deployed in Rohini, Delhi at a substation operated by Tata Power-DDL. Once completed later this year, the 10 MW solution will enable better peak load management, add system flexibility, and enhance reliability for more than 7 million customers in the Delhi region.

Fluence, an energy storage technology and services company owned by Siemens and AES, will supply its Advancion technology platform for the project. Tata Power-DDL and its customers will benefit from Fluence’s proven and industrial-strength storage technology, which was designed for long-term dependability. Fluence brings more than a decade of grid-scale battery-based energy storage experience to the project, with nearly 500 MW deployed or awarded across 15 countries.

“AES has always been an innovative company, providing safe, reliable and affordable energy to the markets we serve. The deployment of cutting-edge energy storage technology in India shows the commitment we have to the country. Adding Fluence’s Advancion energy storage solution will allow us to continue to contribute to the modernization and enhancement of the electricity system in India,” said Mark Green, President of AES’ Eurasia Strategic Business Unit.

“Tata Power-DDL has introduced several firsts in the distribution sector and implemented various smart grid technologies. We are privileged to implement India’s first utility-scale storage solution in collaboration with AES and Mitsubishi Corporation. The first of its kind system will help to create a business case for the deployment of storage in India, to address challenges in the areas of peak load management, system flexibility, frequency regulation and reliability on the network. This project will provide a platform to demonstrate energy storage as a critical distribution asset and help to balance distributed energy resources, including rooftop solar,” said Mr. Praveer Sinha, CEO and Managing Director, Tata Power-DDL.

India’s renewable energy sector is experiencing remarkable growth and India recently expanded its renewable energy target to 175 gigawatts of solar and wind generation by 2022. Deploying energy storage will help network operators mitigate solar and wind resources’ variability and reduce congestion on the region’s transmission system, delivering more affordable, clean energy and enabling new sources of revenue from frequency regulation and other grid services.

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National Grid, a US transmission company, and the Department of Energy’s Pacific Northwest National Laboratory have entered into an agreement to work together on research in the areas of transmission grid modernization and energy storage technologies.

The electricity industry is undergoing sweeping changes, including evolving customer expectations, proliferation of renewable and distributed energy resources, and state energy policies that are affecting what the transmission grid is being asked to do.

Both parties are focused on creating a robust, flexible, secure grid that will deliver the nation’s clean, reliable, and affordable energy future. They will collaborate on topics such as:

·      Grid-scale energy storage;

·      Advanced transmission network controls and monitoring;

·      Integration of distributed and renewable energy resources; and

·      Enhanced grid cyber protection.

“I’d like to congratulate National Grid and PNNL on today’s announcement,” said Secretary of Energy Rick Perry. “Innovation partnerships with the private sector are critical to the groundbreaking work our National Labs undertake. DOE is committed to the modernization, reliability and resiliency of our grid and expanding energy storage research and this partnership is a great example of that commitment.”

“This collaboration is a natural outcome of our organizations’ mutual goal to optimize the benefits and value the transmission network can deliver to our customers, communities and country,” said Rudy Wynter, president and COO of National Grid’s FERC-regulated Businesses. “We are delighted to work with the experts at PNNL to make this vision a reality.”

“A reliable and resilient electric grid is critical to our national and economic security,” said PNNL Director Steven Ashby. “This agreement with National Grid will explore how to best integrate new technologies, like energy storage, onto the grid to improve grid reliability and resiliency in the face of severe weather events, cyber threats, a changing mix and types of electric generation, and the aging of the electricity infrastructure.”

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A megawatt-scale lithium-ion (Li-ion) energy storage system (ESS) can be vital in successful grid integration of a large wind or solar plant by addressing the intermittency and unpredictability inherent in renewable energy. The challenge, however, is sizing the ESS for maximum operational and financial benefit. This is because an ESS can have several distinct roles, and only by understanding its role and the specifics of its site can engineers specify the right ESS for the job.

Ramp Rate Control

Grid operators often must limit the rate of change at which power is injected into the grid-the ramp rate. The output of a photovoltaic (PV) array of several megawatts can drop by 70 to 80 percent in about a minute. The ESS, therefore, must discharge in a way that ramps the net facility output down smoothly over seven or eight minutes (Figure 1). The ESS can absorb or release energy when a sudden shift in wind or passing cloud causes a step change in output. Ramp rate control ensures that the facility ramps at a rate that is compatible with the power system. This is particularly true for island grids, because they lack the inertia of mainland networks and are susceptible to disruption, which could be caused by simultaneous uncontrolled ramping of several renewable facilities.

The ESS will experience many small charge and discharge cycles. Over the day, the cumulative energy charged and discharged in 24 hours, known as throughput, can amount to around two to three multiples of the capacity of the ESS (2C to 3C).

Typically, a 10 MW solar farm would be combined with an ESS capable of delivering 5 MW of power and storing 1.3 MWh of energy. The facility would operate at an average depth of discharge (DOD) of 6 percent and a cumulated daily energy throughput of 2.5 MWh, which is equivalent to 1.9 times the capacity (1.9C).

In contrast, wind generation generally varies at lower amplitudes so a typical 10 MW wind farm could be equipped with a 2.5 MW ESS, delivering 0.58 MWh energy storage. It would operate at an average DOD of 4 percent with a cumulated daily energy throughput of 1.9 MWh, or 3.2C.

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Go Electric won a $499,506 contract by Electricore for a demonstration microgrid project at the Fort Custer Training Center in Michigan.

The project is funded by the Environmental Security Technology Certification Program (ESTCP), a Department of Defense program for promoting the transfer of proven innovative technologies into field use.

Go Electric will deliver a 400 kW/160 kWh battery energy storage system and will provide engineering support for the installation and commissioning of the energy storage system into a facility-wide microgrid. Go Electric will also support the integration of a microgrid controller provided by power management company Eaton.

Electricore, a non-profit consortium formed at the request of the Department of Defense to implement advanced energy, transportation and electronics technologies, is leading the project with support from Eaton and local utility Consumers Energy. The Michigan Army National Guard, which uses Fort Custer alongside several other units, is hosting the project.

The microgrid will enhance power surety, energy resilience, distributed generation management and demand response, while contributing to the critical power needs of nearby military installations. In addition to the 400 kW system, the microgrid includes 1.375 MW of legacy diesel generators and 720 kW of photovoltaics.

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The U.S. Department of Energy’s National Renewable Energy Laboratory and Clean Energy Group (CEG) have released the first comprehensive public analysis detailing the potential size of the commercial behind-the-meter battery storage market in the United States.

NREL analyzed over 10,000 utility tariffs in 48 states, finding that more than five million of the 18 million commercial customers across the country may be able to cost-effectively reduce their utility bills with battery storage technologies.

These findings, grouped by utility service territory and state and illustrated in a series of maps and tables, are presented in NREL and CEG’s white paper, Identifying Potential Markets for Behind-the-Meter Battery Energy Storage: A Survey of U.S. Demand Charges, available here.

The researchers looked at the number of commercial customers eligible for utility rate tariffs that included demand charges of $15 or more per kilowatt, an industry benchmark for identifying economic opportunities for behind-the-meter storage.

They concluded that nearly five million customers were at or above this demand charge threshold, accounting for over 25 percent of commercial customers in the United States. This represents a substantial market opportunity for behind-the-meter battery storage, which can be installed to control peak demand and lower electricity bills by reducing demand charges.

The analysis determined that economic opportunities for storage exist not only in first-mover states like Californiaand New York, but also across the Midwest, Mid-Atlantic, and Southeast. For example, tens of thousands of commercial customers in Georgia, Alabama, Kentucky, Michigan and Ohio may be subject to utility tariffs with sufficiently high demand charges to make storage a viable economic investment. Anticipated future declines in battery storage costs would enlarge the market potential in these and other states.

“With this analysis, we have identified the areas where customers have the greatest potential to benefit from investments in battery storage,” said Seth Mullendore, coauthor of the paper and a project director at CEG. “Utilities know where these opportunities exist, and now the rest of us have that information too.”

Nearly all medium to large commercial customers in every state are subject to utility demand charges, yet customers often do not understand how these charges are structured or accounted for. (For more information about demand charges, see the accompanying fact sheet here).

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A recent project in California may be the first of its kind—at least in the U.S.—in which large-scale batteries actually fired up a generator to restore the grid operations without a power feed from the transmission network or backup source. In May, the Imperial Irrigation District’s (IID)  new energy storage system provided the electricity needed to get its 44-MW combined-cycle natural gas turbine going at the El Centro station .

This is a big deal in the expansion of energy storage capabilities, proponents say.

“From where I sit and what I know, I’m not aware of anybody else able and willing to do so,” said Mirko Molinari, manager of distributed energy resource development for GE Power, one of the partners in the IID energy storage project.  “It was not a simple task.”

Energy storage systems play several roles within the grid connection, from load following to load smoothing to frequency regulation. Now, at least in this case and likely others to follow, it can play a startup role before converting back to absorbing power from the functioning grid.

“The biggest question is whether this is a game changer,” said Matt Roberts, vice president of the Washington, D.C.-based Energy Storage Association. “No, but it’s one of the new value streams this system can deliver.”

Juggling all of those streams is exceedingly complex, GE’s Molinari pointed out. Software and control systems must wade through all the immediate and intermittent inputs of a grid system which is processing flow from renewables as well as facing resiliency challenges once a gap develops in electron flow.

“The grid is the biggest machine ever built by humankind,” Molinari noted. “All of these renewables are pushing a lot of complexity down to the grid management. . . How do you manage all of this together?”

IID’s energy storage system went online in October 2016, and the black start was performed nearly seven months later in May. The partners in the project include Coachella Energy Storage Partners LLC, ZGlobal Inc. and GE Energy Connections (now part of GE Power).

Historically, an operative grid would be restarted by a backup diesel generator or some other form of generation, giving the main turbine time to get going again and synchronize and keep frequency steady on the system.

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Power provider Aggreko is jumping big into the energy storage sector with its acquisition of Younicos announced this weekend.

The Energy Storage Association announced that advanced energy industry veteran Kelly Speakes-Backman will become the organization’s first CEO, effective July 1.

“As evidenced by our recent ’35 by 2025 Vision’ announcement, in which we see the potential for 35 GW of new energy storage additions to the U.S. power grid by 2025, our industry is in the midst of an explosive growth stage,” noted Praveen Kathpal, vice president of AES Energy Storage and chair of ESA’s board of directors. “As our industry expands, ESA must also expand to ensure our messages are clearly heard by regulators, industry players and other stakeholders, while also supporting our members with the insight and tools necessary to navigate the dynamic environment such growth creates. Kelly’s diverse experience as a state regulator, industry executive and trade association leader will enable ESA to take the next step in its evolution to fully support the energy storage industry as it enters this rapid expansion phase.”

“I am thrilled about the opportunity to lead ESA in service to its members and the energy storage industry overall in this era of exponential growth,” added Speakes-Backman. “For over 20 years, I have worked to help the energy efficiency, distributed energy and renewable energy sectors evolve. I’m going to do everything in my power – working closely with ESA’s members, government officials and the energy industry – to make sure energy storage becomes an integral linchpin of the modern power system.”

Speakes-Backman joins ESA from the Alliance to Save Energy, a premier trade association representing the energy efficiency sector. As the Senior Vice President of Policy and Research, she directed the policy efforts, working closely with industry and policy makers to advance energy efficiency. Prior to that, Speakes-Backman served as a Commissioner at the Maryland Public Service Commission and the Director of Clean Energy for the Maryland Energy Administration. Earlier in her career, she held strategy, marketing and sales roles at SunEdison, UTC Power, Wärtsilä and Jenbacher.

As part of ESA’s evolution, Matt Roberts will assume the role of Vice President. In this capacity, Roberts will build upon the growth, policy impact, and market recognition that ESA accomplished under his leadership over the last three years as ESA’s first executive director.

“Working together our industry has grown tremendously, and is transforming the future of the power sector. We are very excited to build upon ESA’s successes and look forward to working with Kelly on advancing ESA’s mission to propel the energy storage sector into a multi-billion dollar industry,” said Roberts. “Now that we are at this stage I can fully devote my energies to what I have been most passionate about: growing ESA’s impact by empowering our members and educating stakeholders throughout the power ecosystem.”

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Stem Inc. activated several of its virtual power plants, networks of energy storage systems located at business and institutions throughout the state, multiple times during a heat wave last week, automatically dispatching stored energy to provide emergency demand response services to the California System Independent System Operator (California ISO) and three power utilities.

As a heat wave approached California on June 19, 2017, energy prices in the day-ahead wholesale market rose, signaling a need for resources that could act quickly to increase energy supply or reduce demand to prevent widespread blackouts. Having regularly offered stored energy from its network into the California ISO markets since 2015, Stem’s latest bids started to clear.

Stem first committed to reduce energy demand for Pacific Gas & Electric (PG&E) and Southern California Edison at 5 pm PT on June 20 through the Day-Ahead settlement process the night before. Then at 5:15 pm on June 20, while already dispatching in four areas within the PG&E and SCE service territories, additional Stem offers to provide energy with less than five minutes’ notice were accepted further south in three parts of San Diego Gas & Electric’s (SDG&E) service territory. Stem stepped up, dispatching energy storage systems at customer locations across seven utility zones to deliver on-time and more than promised.

In this one hour, Stem delivered stored energy from its customer network to seven strained areas of the CA grid simultaneously at the height of a heat wave. Acting as virtual power plants, aggregations within the Stem network automatically responded to rising wholesale prices in as little as five minutes to dispatch 1.6 MW of targeted relief, 21 percent more than committed. Stem’s network similarly dispatched fast, on-demand power 10 more times across the three utilities’ service territories in the remainder of the week as the heat continued.

In California, Stem uses the CAISO Proxy Demand Response (PDR) mechanism to aggregate DERs, and has been a very active participant in their wholesale market over the last three years. CAISO prices have cleared higher than the bids of storage-based demand response providers more frequently than expected in 2017. For example, Stem’s network responded to 150 “real-time,” or five-minute dispatch events for SDG&E from January to May of 2017. Stem is the leader in bidding aggregated distributed energy resources (DERs) into wholesale markets in California and across the U.S.

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