Solar energy is on the rise, but the news isn't all sunny. Experts say it could be tricky to integrate solar power generation facilities into the existing electrical distribution grid, especially with today's rapid pace of solar deployments. Estimates are that by the end of 2011, solar generating capacity is expected to reach 40 GW worldwide, with the U.S. alone doubling its capacity between 2010 and 2011, from 1 to 2 GW.
Trouble is, the utility grid may not be ready for all this solar capacity. The consulting group Accenture found that 72% of utilities it surveyed think their grids will face challenges or require upgrades before solar PV can account for a significant percentage of power generation.
One factor utilities are concerned with is safety — specifically, what happens when grid power goes down but a PV array connected to it continues to generate juice. Such a condition is dangerous to workers repairing the lines. With high levels of PV, say Accenture analysts, the PV systems themselves may support the line voltage even during an outage, creating a power “island” — remaining online during the outage and creating a safety hazard.
To avoid such calamities, PV systems connected to the distribution grid must be able to shut down their inverter(s) for a minimum of five minutes when line voltage drops below a certain level and stay off until the voltage level has been restored.
PV systems also tend to raise the line voltage. Too many of them on a given section of the grid could boost the line voltage past its upper limit. On the other hand, a sudden drop in PV output caused by clouds could drop the line voltage too quickly for built-in system voltage regulation to respond. And line voltage above or below preset limits might cause other PV systems to trip offline.
Making matters slightly worse, clouds moving over relatively large PV arrays create a concern about voltage fluctuations at the point of connection with the grid. This “flicker” is not expected from normal PV operation, but could be a power-quality issue for utilities that must respond to customer complaints.
The DoE is well aware of these concerns. It hosted a recent technical workshop on what happens when there is a high penetration of PV systems into the distribution grid. The upshot: Participants see a need for two-way controls between PV plants and central facilities, and inverters able to react to grid needs such as voltage support. Also on the wish list are improvements in standards and codes such as IEEE 1547, the standard for interconnecting distributed sources with electric power systems.
The Electric Power Research Institute (EPRI) says current industry practices for integrating smart, communicating inverters into utility systems are scarce and largely proprietary. EPRI — along with the DOE, Sandia National Laboratories, and the Solar Electric Power Association — in 2009 began identifying grid-friendly inverter and charger capabilities to help promote standardization. EPRI is preparing for the day when grid operators will need to monitor and manage large numbers of distributed generators — not just PV and wind farms, but battery banks and even EVs plugged into charging stations with capacity to spare. The good news about this scenario is that with the right kind of inverters, such distributed generators can help stabilize the grid and minimize local voltage variations.
One obstacle in the way of this goal is a lack of common terms for managing inverter-based systems. Toward that end, efforts are underway to identify inverter capabilities that should be standardized and develop a standard communication protocol for distributed grid support.
Standards for solar integration
As renewable power installations grow larger, they start to take on some of the qualities and concerns of conventional power plants. EPRI technical executive Thomas Key notes that renewable systems, in low numbers, are unstable during outages because they cannot match the grid load level, and therefore pose little threat of islanding. But large renewable installations do indeed represent potential islanding threats that might demand relatively expensive external multipurpose relays and transfer tripping schemes. PV inverter anti-islanding protection must intentionally destabilize otherwise balanced generation and load, according to Key. For example, UL-1741, the safety standard for inverters and controllers used in independent power systems, prescribes tests to verify that inverters trip within two seconds after loss of grid connection.
And there are potential ambiguities associated with the connection of privately owned renewable resources to the public utility grid. Responsibility for safe operation of a renewable power facility falls on its owner. But public utilities must manage the overall grid and the distributed resources connected to it. There's much discussion about how best to set up this partnership, says Key.
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To keep operations stable, different ideas for communication schemes and autonomous reaction modes are being considered that will let distributed systems react quickly to destabliziing conditions. One idea is to create a “central utility” that will communicate with all parts of the grid, says Key.
With regard to PV, the industry is leaning toward incorporating intelligence into the PV power electronics so PV systems can autonomously respond without relying on constant communication with the utility. According to Key, the way individual PV systems are set up with anti-islanding functions is working well for now — but won't work as well when PV contributes a more significant portion of grid energy. PV has one advantage in that its power electronics can simplify grid integration more readily than those of other distributed generation sources such as wind power. Wind farms, for example, may require external capacitor banks for reactive power support. External capacitors are not necessary with PV, according to Key.
At today's low penetration level for PV (less than 2% of overall grid energy), problems at PV installations likely have do not hurt normal feeder or grid operation, says Key. When solar PV reaches a medium level of penetration, 2% to 6% of grid energy, distributed PV will begin to affect the feeder voltage. Utilities may need to widen the voltage trip limit, adjust circuit voltage regulation, and adapt circuit protection settings. Interconnection standards will also need to be adjusted to consider these feeder-level interactions.
At higher penetration levels, 6% or more of grid, PV systems will begin to affect utility feeds and grid balancing and have to be considered in both planning and operation strategies. Ramp rates may need to be controlled at the grid level as well, notes Key.
Finally, new standards will need to address voltage and energy support, allowing voltage regulation, low voltage, and under-frequency ride-through.
Solar energy grid integration projects
The SunShot Initiative is a collaborative effort to develop solar energy technology and make solar power cost-competitive with other forms of energy by the end of the decade. Eight projects are targeting ways to develop electronics and build smarter, more interactive systems and components so that solar energy can be added into the electric power distribution and transmission grid at higher levels. The DoE plans to fund projects in this area that include:
Electric Power Research Institute: Develop, implement, and demonstrate smart-grid-ready PV inverters that include grid support and the utility communication-and-control links needed to capture the full value of distributed PV assets.
General Electric: Demonstrate a cost-reduction approach for an ac PV module driven by innovations in micro-inverter design, module integration and packaging, and integration with a new intelligent circuit breaker.
SatCon: Develop and demonstrate a control architecture for PV inverters that virtually eliminates the effects of voltage variation caused by PV generation variability.
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