NATIONAL RENEWABLE ENERGY LABORATORY
On the Path to SunShot: Emerging Issues and Challenges in Integrating High Levels of Solar into the Electrical Generation and Transmission System
Achieving the U.S. Department of Energy’s SunShot Initiative cost targets could greatly accelerate deployment of grid-integrated solar technologies. Global experience with increasing amounts of wind and solar on power systems has shown that variable generation resources can be integrated into the grid at penetrations well beyond current capacity. However, the prospect of dramatically increased photovoltaic (PV) deployment requires detailed examination to ensure that high-penetration solar technologies will provide their intended benefits, including reducing fossil fuel use and reducing the conventional capacity needed for reliable service. This report examines several aspects of how the bulk power system (consisting of traditional generators and the high-voltage transmission network) may need to evolve to accommodate the increased PV penetration resulting from achievement of the SunShot cost targets.
The characteristics of PV-generated electricity—including variability, uncertainty, and non-synchronous generation—present challenges to large-scale, cost-effective grid integration by reducing PV’s energy value (and thus its ability to displace fossil fuel use) and capacity value (and thus its ability to replace conventional capacity). One challenge to realizing the full energy value of PV is the need to accommodate the changing net load (normal load minus generation from variable solar and wind sources) associated with high midday PV generation and low electricity demand. This situation can create “overgeneration,” when conventional dispatchable resources cannot be backed down further to accommodate the supply of PV and other variable generation (VG). Because of the threat of system disruptions from power supply exceeding demand, system operators might curtail PV output and thus reduce the economic and environmental benefits of PV energy. Similarly, the net load changes due to high PV penetration reduce PV’s ability to displace conventional generation capacity during high-demand periods.
Accommodating the changes in net load resulting from increased VG penetration requires enhancements to a power system’s “flexibility,” or the ability of the grid and generation fleet to balance supply and demand over multiple time scales. Numerous technologies and strategies for increasing flexibility have been implemented already, are being implemented today, or are being developed. These approaches allow VG to be used directly to offset demand and increase instantaneous VG penetration, or they improve the alignment of VG supply and demand. We describe six of these flexibility options:
- System operation—Changing the way the grid is scheduled and dispatched, including changes to market rules, does not require new technologies and often represents the “least cost” way to aid VG integration.
- Flexible generation—Generators can respond better to the net load shape created by additional PV via increased ramp rates and ranges as well as the ability to start and stop more frequently.
- Reserves and stability services from VG—Inverter-based wind and solar plants can provide the grid’s frequency response needs as these plants become a larger proportion of the generation fleet and new mechanisms are developed.
- Transmission and coordination—Balancing supply and demand over larger areas reduces net variability of both load and renewable resources such as PV owing to greater spatial diversity of VG resources.
- Demand response—Voluntary load reduction or load shifting can provide multiple benefits to integrating solar and reducing curtailment, including reducing the dependence on partially loaded synchronous generators for providing frequency stability and operating reserves and changing the shape of the net load, which can reduce ramp rates, better align solar supply with demand, and reduce peak capacity needs.
- Energy storage—Like DR, energy storage can provide reserves, change net load shape to minimize ramping requirements, and shift supply of VG to periods of increased net load.
Deploying such grid-flexibility options can increase the energy and capacity value of PV to the grid. We use grid simulations to examine the impact of “near term” flexibility options in California, likely the first large region in the U.S. to experience significant impacts of PV on the transmission network; for this reason, we use California as a case study to examine how flexibility effects cost-effective integration of solar resources. Lessons learned from this region may assist other regions in developing strategies to mitigate the impacts of variability and uncertainty of the solar resource. Figure ES-1 demonstrates the levelized cost of energy (LCOE) from PV in California under two scenarios. The first is a limited-flexibility scenario, which reflects many historical grid operation practices that restrict participation of PV and other distributed resources in participation of grid services. The second is an enhanced-flexibility scenario which includes several grid-management techniques and technologies that will be or could be deployed by 2020. The base cost of PV assumes achievement of the SunShot target of 6 ¢/kWh as well as zero curtailment. The figure shows the steep increase in marginal PV LCOE (the incremental cost of an added unit of PV energy) due to curtailment at penetrations beyond about 10%. Marginal costs are particularly important when comparing PV to other generating options—by the time PV provides 20% of annual electricity demand, marginal curtailment-related costs erase the benefits of achieving the SunShot targets. The figure also shows, however, that flexibility enhancements can minimize curtailment and keep PV competitive at penetrations at least as high as 25%. Similarly, flexibility options such as demand response and energy storage can mitigate declines in capacity credit by exploiting how PV reduces the length of peak demand periods while also reducing the time between on- and off-peak periods.
Looking beyond the 2020 timeframe, our analysis shows how energy storage could facilitate the cost-effective integration of even higher PV penetration. Figure ES-2 shows the marginal curtailment curve when concentrating solar power (CSP) with thermal energy storage (TES) is added to a system with significant PV. In this case, CSP is added starting when solar provides about 28% of total demand and marginal curtailment of PV is 30%. Adding significantly more PV to this system will produce very high curtailment (greater than 50%). The dashed line shows the transition to the addition of CSP with TES. Adding a unit of CSP with 6 hours of TES and enough capacity to provide about 1% of additional solar generation will reduce marginal curtailment to about 10%, and this value could be lower with greater amounts of TES. This is one of many possible deployment scenarios—a more comprehensive analysis of renewable portfolios and flexibility options would help with determining the most cost-effective mix of technologies and strategies.
About the National Renewable Energy Laboratory (NREL)
NREL develops clean energy and energy efficiency technologies and practices, advances related science and engineering, and provides knowledge and innovations to integrate energy systems at all scales.