The adoption of renewable energy is expected to increase across the U.S. Projections from the federal Energy Information Administration indicate that from 2020 to 2050 utility-scale wind capacity will grow by 20 gigawatts (GW) and utility-scale solar photovoltaic capacity will grow by 127 GW.
However, in order to fulfill these aspirations most power systems will have to deal with operational limitations that prevent large amounts of variable renewable generators from being integrated into the energy mix at any given time. These limitations have been identified by grid operators in Texas, Ireland, and the United Kingdom and are related to the speed at which resources can respond to imbalances between electricity demand and supply.
Grid Resiliency and Inertia
One of the main tasks of grid operators is to keep electricity generation and demand balanced at all times as sustained imbalances result in blackouts and system failures. Currently, most electricity systems rely on a form of energy storage known as synchronous inertia to help overcome imbalances between electricity demand and generation. It is provided by conventional generators and motors that are synchronously connected to the grid and it is deployed instantaneously to oppose changes in system frequency due to resistance provided by rotating masses.
For example, a spike in demand will cause the energy stored in the rotating masses of on-line synchronous generators to be released instantaneously, giving enough time for frequency response mechanisms to deploy and arrest frequency decay, avoiding disturbances to grid frequency that can cause non-synchronous generators to trip. In a nutshell, synchronous inertia functions much like shock absorbers on your car that limit the impact of bumps or holes in the road.
In the coming years, the level of synchronous inertia is set to significantly decline as more renewable generation is integrated, potentially limiting the maximum share of renewable sources in the energy mix at any given time. Most non-synchronous generation, including solar PV and wind turbines, rely on power electronics to convert primary energy into electricity. This kind of generation is not as effective at acting as a shock absorber because although the response is very fast, there is no rotating mass able to provide synchronous inertia. System operators have defined parameters that help identify operational limits to the amount of non-synchronous generation that can be integrated into the grid at any given time.
In Ireland, grid operators have defined the system non-synchronous penetration (SNSP) ratio as a way to estimate the maximum share of non-synchronous generation in the energy mix that can be integrated at any given time without jeopardizing system stability. This ratio is currently estimated to be 50 percent.
Similarly, the Electric Reliability Council of Texas (ERCOT) defines critical inertia as the minimum inertia level at which a system can be reliably operated. ERCOT has identified its own critical inertia to be 100 GWs. As a reference point, the lowest verified inertia in Texas in 2017 was 130 GWs. This happened in the month of October, on a windy night at 4 am when demand was at its minimum levels and the penetration of non-synchronous generation was 54 percent.
To overcome operational limitations and guarantee security of supply, grid operators are developing new network codes and are redesigning their ancillary services markets with the aim to procure synchronous inertial response (SIR) and other auxiliary products. The most advanced system services market is the Irish one, where grid operators have designed innovative system services including SIR and have published a system services proven technologies list. For SIR this includes energy storage technologies that rely on rotating masses to generate electricity (e.g. pumped hydro) but excludes energy storage technologies that rely on power electronics (such as battery-based storage). This is because, as noted by ERCOT in a 2018 workshop on SIR, “only synchronous machines provide inertia to the system, everything else provides a response, but does not provide system inertia.”
An additional technology that can provide synchronous inertial response is Liquid Air Energy Storage (LAES). LAES systems use motor-driven compressors to liquefy air and charge the energy store and a turbine-driven synchronous generator to inject power to the grid. Thus, both the charging and the discharging units of an LAES system can provide synchronous inertia.
Interestingly, both units can run concurrently and although this might look odd at first, this mode of operation could prove to be very valuable at certain times. For example, system resiliency tends to be very weak when electricity demand is at its minimum level and the penetration of non-synchronous generation is high. These events occur across the year, normally at night or on sunny summer weekends when people are on vacation. In this scenario, few conventional generators serve system load, reducing system inertia to minimum levels. Under these circumstances fluctuations from renewable generation may create imbalances that need to be resolved more quickly than normal to avoid major system failures, impacting the cost to operate the system.
Managing the costs associated with operating the system under low synchronous inertia conditions will entail minimizing renewable curtailment and procuring cost effective system services. Operating the charging unit of an LAES system would not only help avoid curtailment but would also contribute to providing synchronous inertia. Additionally, the discharging unit could be operated at its minimum export level or even operated as a synchronous condenser contributing to system inertia and voltage control. This would result in a reduction in the amount of fast reserves needed for frequency and voltage control.
Given the operational capabilities of most electricity grids around the world, there is a limit to how much renewable energy can be integrated at any given time while maintaining grid resiliency. Operating the grid with low levels of synchronous inertia would prove to be expensive, especially when demand for electricity is low.
For these reasons, energy storage options such as LAES that provide synchronous inertia could help to reduce costs by reducing renewable curtailment. In turn, this reduces the need for faster responding resources for frequency control and could be a key element in creating a cost-effective portfolio of solutions that help to maximize the benefits of renewable energy integration.
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Author Fernando Morales is Lead Business Analyst at Highview Power.
