While in the past, the use of DER solutions such as energy storage and demand response have been thought of in terms of how they defer the use of traditional items in the grid developer’s toolkit, better consideration is forming around the “upfront role” DER can play, a US-based analyst has said.

Energy-Storage.news spoke with Samir Succar, a director and DER analyst at consultancy group ICF, shortly after he spoke on a panel at Solar Power International / Energy Storage International with National Renewable Energy Laboratory (NREL) analyst Kristen Ardani and Interstate Renewable Energy Council (irec) VP of regulatory affairs Sara Baldwin in Salt Lake City, Utah last week.

The panel, ‘Distribution system planning data for project development’, looked closely at the ways and means different stakeholders in the electricity system have for assessing their requirements and planning according.

We briefly reported last week that Irec’s Sara Baldwin had said the deployment of DER needs to scale with the demand for the services they provide, without becoming a neat technology without a niche, as can often happen.

ICF’s Samir Succar highlighted some of the challenges that exist in terms of gathering and using data, especially as more and more DERs are aggregated on the grid. The system, he said, is becoming “more complex, more dynamic, both in the way you operate the system and also in terms of how you then plan and build the system as well.”

“That has implications for DER developers that are looking to not only interconnect on the system but maybe get access to value streams, distribution services, participate in wholesale markets and build that into how they think about their project and their project fundamentals,” Succar said.

Curtailment risk and the need for transparency
Managing constraints on the distribution system and figuring out how to “proactively build the system” to enable DERs to participate more broadly across different services and applications, mean that the top-down planning process becomes vitally important in “both understanding and building those capabilities that then enable functionality and additional revenue opportunities for DER,” the analyst said.

A legislative package for energy storage research and development (R&D) has been welcomed by the US Energy Storage Association, after receiving approval from the Senate Energy and Natural Resources Committee.

An amended version of the Better Energy Storage Technology (BEST) Act was last week approved by the committee after having been introduced in May alongside the Promoting Grid Storage Act of 2019 .

The BEST Act now forms a package of energy storage bills, including language from the Promoting Grid Storage Act of 2019, the Expanding Access to Sustainable Energy Act of 2019, the Reducing the Cost of Energy Storage Act of 2019 and the Joint Long-Term Storage Act of 2019.

Kelly Speakes-Backman, CEO of the US Energy Storage Association, lauded the approval as “another milestone on the path to a better and brighter energy future”.

“Legislation approved today by the Senate Energy & Natural Resources Committee will for the first time elevate energy storage to one of the top priorities of US technology research, development, and demonstration.”

The BEST Act is set to amend the United States Energy Storage Competitiveness Act of 2007 to establish a research, development, and demonstration programme for grid-scale energy storage systems, and for other purposes.

The programme would have an aim of reducing the cost and extending the duration of energy storage systems.

Specifically, research would focus on highly flexible power systems with a minimum of six-hour storage durations, long duration storage systems with 10 to 100 hours of storage durations, seasonal energy storage that could reach durations of weeks or months and the integration of vehicle batteries with the grid, as well as other innovations.

The Department of Energy (DOE) would also be required to carry out up to five grid-scale energy storage demonstration projects by the end of fiscal year 2023, as well as to develop a ten-year strategic plan for energy storage RD&D.

With threats to electric reliability increasing, it is easy to understand why power outages worry retailers. So what are the solutions?

The most obvious is a backup generator. While this may seem like an expedient solution, procuring backup generators is costly and complex. Their purchase requires sizing analysis, engineering, building permits, construction, and routine maintenance that includes inspection, loaded testing, and fuel conditioning if they use diesel.

Failure to adequately maintain backup generators will create operational problems that a retailer may not discover until it is too late. Backup generators sit idle for most of the year, only running during emergency operations. Because of this infrequent operation, maintenance is sometimes skipped, making backup generators less likely to work when needed and far less reliable than a microgrid. In contrast, microgrids frequently interact with the grid, so they undergo constant testing and conditioning, increasing the likelihood they will work during an emergency.

The heart of a microgrid
It is important to understand what a microgrid is and how it functions, and how is can contribute to electrical reliability. As the name suggests, a microgrid is a smaller version of the electric power grid installed on-site at the user’s facility.

A microgrid can serve a single building, a business campus, a college campus, a military base or even a community. A microgrid’s defining characteristic is its ability to operate in isolation from the surrounding grid.

When designed for resiliency, a microgrid’s defining characteristic—what makes a microgrid a microgrid—is its ability to operate in isolation from the surrounding grid. A grid-connected microgrid ‘islands’ from the central grid when it senses a disruption, such as a power outage. The microgrid then activates its system to supplant the lost grid electricity.

Islanding occurs via a microgrid controller, the technology at the heart of the microgrid, which allows the microgrid to interact with the central grid. When it senses a problem on the grid, the controller sets up the activities to ensure power flows to its host from the on-site system. Retailers are able to maintain continuous operations, despite severe weather or other grid threats.

A microgrid also can provide advantages to a retailer by interacting with the grid during non-emergencies. For example, the microgrid may sell services to the grid or leverage changes in pricing, which can produce a revenue stream or offset microgrid costs.

In 30 years since commercialisation, lithium-ion (li-ion) batteries have been used in an increasingly diverse range of products, starting from early generation handheld electronics to powering cars and buses. Additionally, these batteries are increasingly sought after for utilisation in energy storage applications, often paired with renewable energy generation. The continued decline in battery prices combined with the global trend toward energy grids being powered by renewable energy sources is predicted to increase the world’s cumulative energy storage capacity to 2,857GWh by 2040 [1], a substantial increase from the current capacity of ~545MWh [2], according to recent estimates by Bloomberg New Energy Finance.

These staggering projections paint an encouraging picture for how prominent li-ion-driven energy storage applications will become in the future as the world increases usage of renewable, clean energy sources to power energy grids worldwide. Driven increasingly by electro-mobility as well as grid-scale energy storage applications, the volume of li-ion battery cells being sold is set to surge. The graph in Figure 2 contextualises the relative volume (in tonnes) of new li-ion battery cells forecasted to be sold through to 2025. The growing quantities of li-ion batteries being placed on the markets accelerates the urgency with which the world must find an economically viable, commercial-scale recycling solution for end-of-lifecycle li-ion batteries to be recycled at a ‘mega’ scale. This article will take a closer look at some of the challenges that exist today within the li-ion recycling sector and where opportunities exist to overcome the current roadblocks.

Li-ion recycling industry challenges
Feed Sourcing

Secondary resource recovery (i.e. recycling) has a set of unique operational challenges that need to be addressed concurrent to the development of an economic, advanced technology. For the purpose of recycling, feed materials are typically inherently distributed, making it difficult to collect a high volume of feed for a processing plant. Although the collection supply chains for some analogous industries such as lead-acid battery recycling are well-established and mature by comparison, the li-ion battery recycling supply chain continues to be fluid. Spent li-ion battery sources can be broadly segmented into portable/’small format’ and ‘large format’ sources, which corresponds to the relative voltage of li-ion batteries (i.e. low voltage and intermediate to high voltage, respectively). Each of these types of batteries has a diverse group of stakeholders – from manufacturers, to the dealer network, recycling programmes, electronics and vehicle recyclers. In the context of the energy storage sector, its own diverse group of stakeholders exists – battery technology provider, energy storage integrator, project developer and asset owner. Managing the inherently heterogenous nature of li-ion batteries from a wide range of stakeholders remains a central challenge for companies in the li-ion resource recovery industry.

Logistics and regulations

Li-ion batteries are currently classified as Class 9 Dangerous Goods due their dual chemical and electrical hazard. Li-ion batteries can possibly undergo thermal runaway, typically resulting from internal shorting, leading to fire or explosion. There are numerous factors that can cause thermal runaway, including but not limited to overcharging, environmental conditions (e.g. extreme external temperatures) and manufacturing defects. At the onset of thermal runaway, the battery heats in seconds from room temperature to above 700°C. As part of this complex set of chemical reactions, the electrolyte solvent in lithium-ion batteries – typically alkyl carbonate-based – acts as a ‘fuel’ source for combustion.

SALT LAKE CITY — The first residents of an all-electric and energy efficient community — the largest battery demand response project in the United States — are settling into new apartments. Their cars are tucked neatly beneath solar panel covers and their electric cars can plug into charging ports. Inside each apartment in the Soleil Lofts development, a Sonnen battery is humming silently close to their living room.

The residents sign on knowing their backup power can be controlled by the utility and dispatched to the grid as needed. The circular logo on the Sonnen system will turn green to tell residents when the battery’s power is being used by the local utility, Rocky Mountain Power.

The full complex will be finished in the next two years, but the virtual power plant established when the first building opened is a blueprint for developments outside of Utah, according to the real estate developer Wasatch Group.

The Soleil Lofts apartments, under construction in Herriman, Utah, seeks to attract environmentally conscious customers who want to hasten the transition to all-electric and clean energy living. The project represents a collaboration among Rocky Mountain Power, battery developer Sonnen, solar developer Auric Energy and Wasatch. All the partners have plans for modeling the success of the Soleil projects.

“[T]he long term thing for us is how do we provide battery solutions for our customers?”

Bill Comeau

Managing director of customer innovations, Rocky Mountain Power

The effort is an opportunity for the Pacificorp subsidiary to work with a partner that has experience with energy storage, as the utility learns to better integrate batteries into the grid and enable growth from renewables, according to Bill Comeau, Rocky Mountain Power’s managing director of customer innovations.

When complete, the planned community’s 22 buildings will have 600 apartment units with 12.6 MWh of battery storage, 5.2 MW of solar panels, 150 stalls of EV chargers and an overriding focus on energy efficiency. Utility access to the 600 Sonnen batteries will turn the complex into a grid resource.

“In the big scheme of things, it’s actually really small,” Comeau told Utility Dive. “But the long term thing for us is how do we provide battery solutions for our customers?”

A study in Northern Ireland has shown that appropriately configured energy storage can offset far more than its rated capacity of mechanical inertia, says Jaad Cabbabe, Senior Manager of Business Development at Fluence, and one of the authors of a white paper Redrawing the Network Map: Energy Storage as Virtual Transmission, published this month.

The Northern Ireland case study, in which Fluence played a part, showed that 360 MW of energy storage could provide the same inertia to the grid as 3 GW of coal-fired generation, says Cabbabe. He adds, “We believe that same concept is replicable in Australia. The ratio may not be exactly the same, but it will probably be very similar.”

Such technical capability is part of the rationale given in the Fluence white paper for including battery energy storage in transmission planning.

“We wanted to plant the seed in the minds of decision makers and network planners that energy storage should be part of their toolbox when they’re solving transmission problems,” says Cabbabe.

Simon Currie, Principal at Energy Estate, an energy advisory and accelerator business, sees storage as a technology that could encourage greater competition and innovation in transforming the grid to suit the renewable age.

He points out that energy-storage options have already been put forward for the Project Specification Consultation Report on the Western Victoria Renewable Integration Project; and in the scoping study for the new Queensland-NSW Interconnector (QNI). Although storage may not have been the preferred choice for these projects, says Currie, “It’s certainly now on the agenda, which wasn’t the case a year or so ago.”

Currie cites ElectraNet’s Dalrymple ESCRI-SA Battery Project among the successful operational storage-augmented transmission assets in Australia. Dalrymple’s 30 MW/8 MWh battery system supplies fast frequency response capability to reduce constraints on the Heywood interconnector, thereby enabling increased flows of electricity through this key link between the South Australian and Victorian networks.

The Fluence white paper places battery storage in the picture for augmenting interconnectors, increasing the capacity of currently constrained transmission lines, and reducing the cost and footprint of new lines.

Energy storage, says Cabbabe can virtually hold the fort — managing energy flow at junctions in the grid — until interconnectors can be built. Where interconnectors may take seven or more years to be approved, constructed and operating, large-scale battery storage can be operational within 18 months to two years.