In a paper to be published in the forthcoming issue of Nano, a team of researchers from the China University of Mining and Technology have fabricated an asymmetric supercapacitor (ASC) based on FeCo-selenide nanosheet arrays as positive electrode and Fe₂O₃ nanorod arrays as negative electrode. There is evidence that FeCo-selenide could be a promising next-generation electrode material for energy storage devices.

Supercapacitors have been considered as the most attractive candidate for energy storage devices, and are widely used in the field of portable electronic equipment and electric cars due to their high power density, fast charge/discharge rate, low maintenance cost and long cycling life. Similar to the transition metal bimetallic oxide and sulfides, metal selenides can be considered as a promising candidate for electrode materials, as selenium belongs to the same group element as sulfur.

The FeCo-selenide was synthesized using a two-step hydrothermal process, with Ni foam as substrate and current collector. The as-prepared FeCo-selenide nanosheet arrays on Ni foam shows specific capacitance of 978 F/g (specific capacity of 163 mAh/g) obtained at current density of 1 A/g and cycle stability of 81.2 percent was achieved after 5000 cycles. And the ASC device operating at 1.6 V delivers a maximum energy density of 34.6 W h/kg at power density of 759.6 W/kg, which is higher than that of many other ASC reported previously. The practical application of the ASC device was explored by assembling several capacitors into a series circuit to light 1 LED bulb and light board of “CUMT”. The ASC device exhibited excellent electrochemical performance which provides the evidence that FeCo-selenide could be the next-generation promising electrode material in energy storage devices.

The team at China University of Mining and Technology is currently exploring options to better control the high voltage output and create high-performance ASC. For optimal electrochemical performance and decrease in cost, the team would also like to explore a device based on selenide composites in its application.

MISO is planning to provide storage with make-whole payments for price volatility, subject storage resources to dispatch and regulation performance rules, and exempt storage from certain uplift charges, officials said last week at a special conference call on compliance with FERC Order 841.

The RTO is proposing to use the same uninstructed deviation threshold it uses for other generators, Market Quality Manager Jason Howard said during the call on Aug. 21. MISO is currently refining a proposal to implement a more performance-based uninstructed deviation threshold. (See “Final Uninstructed Deviation Proposal,” MISO Market Subcommittee Briefs: May 10, 2018.)

Electric storage resources will be eligible for day-ahead margin assistance payments when they are dispatched below their day-ahead megawatt commitment and revenue sufficiency guarantee payments when they are dispatched in real time above their day-ahead commitments. They will also receive RSG payments when committed above their real-time economic minimum limit when committed in real time under a must-run commitment.

Storage could also be manually redispatched by MISO operators to contradict their day-ahead schedule or real-time offers, even to zero output, RTO staff said.

The RTO is also planning to exempt storage from its revenue neutrality uplift charge, its demand response resource uplift charge, and load ratio share adjustments and ancillary distributions. However, MISO said there was a potential for storage resources to be assessed real-time RSG distribution charges.

MISO plans to vet its performance rules with its Independent Market Monitor.

“We’ve just begun our collaboration with the Market Monitor … so that they do have an initial glimpse of our thoughts,” Howard said. He added that MISO will return with any rule changes regarding threshold and performance at the Sept. 13 Market Subcommittee meeting.

Some stakeholders asked for more specifics about MISO’s Order 841 compliance filing. The RTO said in June it would respond to Order 841 by dividing storage bid parameters into four operating modes: discharging, charging, continuous operations and offline. Market participants will be left to choose a mode for individual dispatch intervals and will also be responsible for managing the state of charge of their storage units. (See MISO Weighing Feedback to Storage Proposal.)

The City of Portland, Portland State University, and Portland General Electric are collaborating on a program to improve disaster resilience in the city through emergency microgrid structures called PrepHubs. An interdisciplinary team from MIT is supporting the effort.

These prototypes are composed of critical lifeline modules forming a flexible kit of parts that can be combined in different ways, according to the program website. “For example, a sidewalk PrepHub allows you to charge a phone, hear a public announcement, and connect with loved ones,” the site explains. A pocket park version has medical supply storage and water tanks, while a civic plaza type contains sanitation services and cooking supplies.

Earlier this month, the Portland City Council voted to approve the PrepHub agreement. PGE will provide power to the PrepHubs from the grid as well as energy storage devices that are supplemented by solar arrays and pedal-power.

“The hubs will be able to recharge emergency communications, equipment, and cell phones during and immediately after a natural disaster,” the partners say. Each hub also offers secure storage for Basic Earthquake Emergency Communication Node (BEECN) cache equipment.

A PrepHub serves as a meeting point to receive resources, reducing panic and helping communities recover, according to the prototype creators. The first one is expected to be installed on the Portland State University campus in 2019.

Each PrepHub is essentially an emergency microgrid. The $300,000 pilot project aims to ultimately build 40 to 50 additional microgrid statues in Portland parks that will become public landmarks, Microgrid Knowledge’s Lisa Cohn reported. Portland will be the first city to have a grid-connected PrepHub, Conrad Eustis, director of retail technology strategy for PGE told the outlet.

“Successful disaster response depends on partnerships,” said Maria Pope, president and CEO of PGE. “This project will also inform PGE’s work to use technological advances to build a smarter, more resilient grid for customers.”

AECOM and Lockheed Martin have joined forces to build a Battery Energy Storage System (BESS) at Fort Carson, Colorado, using Lockheed Martin’s GridStar Lithium energy storage process.

AECOM officials representing the fully integrated global infrastructure firm said the Fort Carson, Colorado, site would be the largest stand-alone, commercially contracted battery at an army base. The 4.25 MW/8.5 MWh BESS is part of an energy savings performance contract (ESPC) project to reduce Fort Carson’s energy costs and increase its energy resilience.

“During project development, our team surveyed the energy storage industry for the optimum solution for Fort Carson,” Annika Moman, senior vice president of AECOM Power and Energy Services Lead, said. “We decided on Lockheed Martin’s GridStar units due to their unique modular architecture allowing for a flexible design and a reduction in operational risk. Our working partnership with Lockheed was vital to our team and Fort Carson in making this ground-breaking project happen.”

While officials acknowledged the current best primary use-case for the BESS is for demand charge reduction, the system may assume additional missions, such as renewables optimization, frequency and voltage support for Fort Carson’s distribution grid and, potentially, microgrid support.

“Lockheed Martin is pleased to collaborate with AECOM to develop and implement the new military infrastructure that will help Fort Carson increase its resiliency and reduce their electricity costs,” John Battaglini, director with Lockheed Martin Energy, said. “The versatility of energy storage is a key enabler for the military’s aggressive goals of achieving energy resiliency.”

It may not be smooth sailing for Pacific Gas and Electric’s landmark energy storage projects.

Totaling 567 MW, 2,270 MWh, the four projects were hailed as the largest battery storage investment ever proposed when PG&E submitted them for approval at the California Public Utilities Commission (CPUC) in late June. However, comments opposing the projects could slow down their approval and implementation.

Already, the state’s Office of Ratepayer Advocates (ORA) and the Direct Access Customer Coalition (DACC) have filed comments opposing the projects, prompting the CPUC to extend the approval process by at least 120 days. The comments raise questions about whether or not the energy storage projects are needed and whether PG&E’s proposal conforms to the commission’s directives.

The recently-filed comments have had very little public scrutiny, as they were only sent to the relevant parties and have not been posted on the CPUC website.

The cost of reliability

In their comments, the ORA, which is part of the CPUC, argues that the energy storage projects are not needed because the deficiency they are designed to fill will be met with new and planned transmission projects. The ORA claims the projects do not comply with CPUC resolution (E-4909) that authorized PG&E to issue a solicitation for the projects.

The resolution is designed to alleviate the need for an out-of-market contract for Calpine’s Metcalf Energy Center, a 564-MW gas-fired plant in San Jose. Calpine had told the California ISO that it would have to take the plant out of service because it was uneconomic, but the ISO determined the plant is needed, granting a reliability must run (RMR) contract.

In the resolution authorizing the storage projects, the CPUC expressed its concerns about the impact the RMR contracts would have on ratepayers and the lack of competition in the RMR process that can lead to “market distortions and unjust rates for power.”

The commission ordered PG&E to enter into energy storage contracts at “reasonable cost to ratepayers” and to take into consideration the cost and value and the results of previous, similar solicitations. But the ORA argues PG&E did not meet the CPUC’s requirements because the utility did not provide “analysis or explain how the cost of the four energy storage projects are reasonable taking into consideration the cost of the Metcalf RMR contract.” Nor did PG&E compare the four contracts to previous energy storage solicitations, the ORA said.

Costs of the energy storage projects are redacted in the public comments. The comments are not available online because they are not filed with the commission. They are only sent to the relevant parties. By law, the utility is required to respond to comments. The CPUC’s industry division will gather all comments and responses and prepares a draft resolution with its recommendation. The commission then votes on the draft resolution.

In early June, Highview Power announced that it had officially launched its first grid-scale liquid air energy storage (LAES) plant at the Viridor Pilsworth site in Bury, United Kingdom (just outside of Manchester). This five megawatt (MW)/15 megawatt-hour (MWh) facility is on the small side to truly earn the title of grid-scale, but that may be beside the point. The critical issue to consider here is that this new technology may ultimately prove to be a cost-effective long-duration energy storage resource that is – unlike compressed air energy or pumped hydro – geographically independent.

Three weeks after the June launch, Highview announced the hiring of Javier Cavada, who had previously served as President of Finnish energy giant Wärtsilä’s Energy Solutions division and Executive Vice President, as their new CEO. Cavada had overseen impressive growth in that division over the past three years and spent 17 years at Wärtsilä. These two announcements were enough to pique my curiosity, so when I had a chance to interview Cavada as well as Highview’s Director of Business Development, Matthew Barnett, I jumped at it.

Long-term storage technologies have had difficulty gaining market traction

There have been multiple long-duration energy start-ups and a few corporate corpses on the road (flow battery companies Enervault, Imergy, and Vizn – all of whom I have covered in past Forbes pieces – spring to mind) in recent years. There are also only a limited number of flow battery sites in operation.

Meanwhile, pumped hydro storage can deliver both capacity and energy, and represents about 95% of the country’s energy storage. As of 2015, the U.S. Department of Energy estimated that there are 50 projects that could deliver 40,000MW of additional storage capacity. But none have been built recently, and the Sacramento Municipal Utility District recently canceled its 400 MW pumped hydro project citing costs and financial risks. Pumped hydro also requires access to significant quantities of water, elevation, and an enormous amount of environmental permitting to withdraw water and construct reservoirs. So that resource probably won’t be the solution to the long-duration problem.

For its part, conventional compressed air energy storage requires enormous tight caverns – and there are simply not too many of those projects around (exactly two: one in Germany and the other in Alabama).

Lithium-ion: good for capacity and less so for long-term energy storage

Finally, lithium-ion is growing rapidly as a storage medium and is already found in multiple projects supporting renewables, supporting the grid, and displacing conventional resources. It’s a critical player in the storage sandbox. In fact, Pacific Gas & Electric recently requested permission from the California Public Utilities Commission for 568 MW/2270MWh. However, these lithium-ion based projects typically don’t support more than four hours of energy for every MW of capacity installed, so they won’t yet go the distance. I was, therefore, curious to find out why Highview might be different, and why they might succeed where others have encountered difficulties.

Minister for Energy Dr Megan Woods attended an event to officially inaugurate the first grid-scale battery energy storage system in New Zealand, hosted by energy retailer and project owner Mercury Energy.

The project, based around a Tesla Powerpack 2 battery system was revealed to be under development in January this year. Energy-Storage.news reported at the time that the 1MW / 2MWh of Powerpacks is connected to existing pumped hydro facilities in South Auckland and used by Mercury’s R&D centre as part of a trial of scalable grid-connected batteries.

Back in January, Mercury said battery capacity at the installation itself could be added to at a later date, and that the system, with a cost of close to NZ$3 million (US$2.01 million), would trial the redispatch of electricity generated by hydro as well as the possibility of using the Powerpacks in energy trading markets. A Mercury announcement this morning also said the project could be used to investigate the redispatch of geothermal energy.

“We see battery storage as playing an increasingly important role in providing a reliable supply of electricity in New Zealand, as we increase our reliance on wind and solar to generate our electricity,” John Clarke, general manager at grid operator Transpower, said.

“We look forward to continuing to work with Mercury throughout the trial and gather key learnings to enable the transition to New Zealand’s sustainable energy future”.

An energy storage system running on Greensmith’s GEMS software platform has been installed at a natural gas generation facility in Hungary, by Greensmith’s parent company Wärtsilä.

While energy storage with renewables have grabbed the majority of headlines within the industry, batteries have also been used in a handful of locations in combination with fossil fuel generators recently. China is developing or has already developed several, while there are other projects in territories including Australia.

Located in the Hungarian capital, Budapest, Wärtsilä’s latest project was commissioned yesterday and is the first ever energy storage project on which the company has performed an EPC (engineering, procurement and construction) role. It is also the Finnish corporation’s first ‘engines-plus-storage’ installation.

Delivered for customer ALTEO, a Budapest Stock Exchange-listed developer of energy projects including renewables in Hungary, the plant combines three of Wärtsilä’s W34SG engines with 6MW/4MWh of battery energy storage. Wärtsilä claims the W34SG engines are suitable for delivering both “flexible baseload and peak load” and can support the grid in performing ancillary services applications. The company also said the engines can reach 49% efficiency in five minutes from start up, allowing for faster ramping times than other comparable generators.

The hybrid installation will operate in ‘virtual power plant mode’ to help regulate the grid, providing primary and secondary frequency regulation services. This will allow ALTEO to participate in electricity market opportunities for those services, generating revenues. The Greensmith GEMS platform was used to integrate the systems together, while the platform’s software will control the delivery of ancillary services, while analysing ongoing changes in market conditions and rate structures.

Wärtsilä acquired Greensmith in mid-2017 after a period of the two collaborating on projects. Shortly before that takeover, the Finnish company’s energy solutions director had talked up the potential of the latter’s software platforms in enabling greater integrations of systems, including hybrids.

“Wärtsilä is a global energy systems integrator and in the future we will continue to see more examples of energy storage and sophisticated software controls being paired with power plants, wind, buildings and hydro to create hybrid solutions that cut carbon, lower costs and optimise generation,” the company’s Energy Solutions division business development manager Markus Ehrström said.

Ice storage has largely proven its worth, with projects utilizing cheaper energy to freeze a solution that can be later used for cooling during times of peak demand.

Viking’s test at the Dreisbach Enterprises’ frozen food distribution center showed a significant drop in weekly energy use and an even greater drop in peak refrigeration load.

In a sign of the increasing interest in thermal energy storage, last year, Massachusetts tapped Genbright and Ice Energy for a $1.5 million grant to utilize thermal energy storage at residential sites, and for peak demand reductions. In California, Ice Energy and NRG Energy partnered on 1,800 Ice Bear 30 storage solutions to commercial and industrial buildings in Orange County, Calif., as part of Southern California Edison’s storage procurement efforts.

Viking’s system is a bit different, it says, utilizing a phase change material that it describes as “a substance with
a high latent heat of fusion which remains near a constant temperature while storing and releasing large amounts of energy.”

Transitioning from solid to liquid, Viking says the phase change material “absorbs up to 85% of heat infiltration and maintains more stable temperatures to better protect food product.”

The result at the Dreisbach Enterprises’ frozen food distribution center was a 20% decrease in weekday energy use, which the M&V report said was countered somewhat by a 5% increase in off-peak weekend consumption, in order to fully recharge the TES.

The net result, Viking’s study concluded, was a 13% reduction of energy consumption for the entire facility each week. More importantly, the TES lowered peak refrigeration load by 251 kW, a 29% reduction for 13 hours each day.

The study “demonstrates that cold storage operators can safely reduce energy costs and utilities can significantly lower demand on the electrical grid during peak periods to defer costly infrastructure investments,” Collin Coker, vice president of sales at Viking, said in a statement.

Viking said it is now in talks to deploy additional TES technology Dreisbach Enterprises facilities.