Because of the rapid pace of PV deployment in distribution systems, many utilities have achieved or will soon achieve penetration levels in excess of 15% by capacity. An ideal example is Hawaii. Pictured is the La Ola PV Plant on Lanai.
Photo by Jamie Keller, NREL/PIX 19697
The amount of solar generation connected to the U.S. transmission and distribution power system is increasing significantly. Factors such as climate change, renewable portfolio standards and incentives, and accelerated cost reductions are driving accelerated growth in utility-interconnected renewable solar technologies. As a result, numerous North American utilities are faced with photovoltaic (PV) installations with aggregate capacities in the megawatt range on distribution circuits. With increasing solar plant sizes and levels of deployment in both transmission and distribution systems, interconnection and operational challenges become more complex.
Effective interconnection of distributed PV systems requires careful attention to ensure compatibility with the existing grid. The electric distribution grid is designed for one-way power flow from the utility substation to customer loads. Introducing a high penetration of distributed PV systems can affect voltage regulation, power flow, and system protection. As the number of PV installations grows, real and perceived risks to grid operations and stability create additional barriers to further growth.
The Systems Integration (SI) subprogram, within the U.S. Department of Energy (DOE) SunShot Initiative, supports critical research and development activities that address technical and cost barriers to large-scale deployment of distributed and central-station solar energy technologies. An important aspect of the overall effort is ensuring that technology development and industry experience are reflected in the procedures that govern interconnection of PV generation into distribution systems.
At the distribution system level, PV installations account for the great majority of the generation installations. One of the steps in the interconnection screening procedure is related to the amount of generation capacity with respect to peak load. Under most applicable procedures, penetration levels higher than 15% of peak load trigger the need for supplemental studies.
Because of the rapid pace of PV deployment in distribution systems, many utilities have achieved or will soon achieve penetration levels in excess of 15% by capacity. SI is actively engaged in monitoring technical issues associated with high penetration and disseminating information so that the industry is able to evaluate whether existing procedures, including the 15%-capacity-penetration screen, continue to serve industry needs.
The 15% screen, which represents the ratio of distributed generation (DG) capacity to peak load, originates from the concern that a DG capacity larger than the connected load could result in the creation of an unwanted or unintentional island, which causes the line section to be isolated from the utility source. As a result, under most existing distribution interconnection procedures (e.g., California’s Rule 21 Generating Facility Interconnections), if the proposed aggregate DG capacity on a line section exceeds 15% of the line-section annual-peak load, then a supplemental interconnection study is required. These supplemental interconnection studies are often time-consuming and expensive—and frequently create a situation in which the proposed PV system application is withdrawn.
Unintentional Islanding
The possibility of unintentional islanding is one of the concerns of system planners when evaluating interaction issues between distributed generation and the power system. Islanding occurs when the DG operates as a separate entity and continues to energize the load after disconnection from the utility source. There are two types of islanding: intentional and unintentional. Intentional islanding is planned in advance and carefully engineered for reliability and power-quality purposes. Unintentional islanding is established by accident.
All DG systems, including PV inverters, are required to implement anti-islanding controls. The formation of an unintentional island represents a failure to detect and disconnect the loss-of-connection to the utility. Unintentional islanding, even if it lasts a short period of time, is a condition to be avoided in utility system operation because of the following risks:
- Safety issue for both line crews and the public resulting from exposure to energized conductors
- Transient overvoltage caused by ferroresonance and ground fault conditions
- Out-of-phase reclosing, leading to potential damage to DG systems, customer loads, and utility-owned equipment
- Increase in restoration time, which may reduce reliability.
Because of the possible impacts of unintentional islands, the IEEE 1547-2003 Standard for Interconnecting Distributed Resources with Electric Power Systems requires DG systems to have anti-islanding protection that detects when an island has occurred and isolates the generator from the utility system within two seconds. As such, the possibility of unintentional islanding is remote, especially when load and power factor do not match the generation.
Active-power mismatch has been used to prevent the risk of islanding. For example, IEEE 1547.2-2008 Application Guide for IEEE 1547 states that when an unintentional island forms and the total DG capacity is less than one-third (33.3%) of the load (a 3-to-1 load-to-generation factor), the DG would be unable to energize the load and support and maintain acceptable voltage and frequency. In other words, the possibility of unintentional islanding can be ruled out in situations where the DG capacity is less than 33.3% of the load or the pre-island loading approaches three times the generation. For PV installations, there is a need for margin to guard against future drops in the minimum load.
Origin of the “15% Rule”
During the initial formulation of California PUC Rule 21 for interconnection of DG, the 15% rule was established to mitigate the risk of unintentional islanding. It assumes that the possibility of unintentional islanding is eliminated when the connected load is higher than the PV system output.
Some statistical analysis and rules of thumb suggest that the annual minimum load on a line section is approximately 30% of the annual peak load. Thus one-half of this estimated annual minimum load or a threshold of 15% was selected as a conservative number to ensure that there is no risk of DG capacity exceeding the load. Using the peak load as a reference is common practice because data on minimum load are not easily available or reliable. Figure 1 shows a sample load curve for a distribution substation in which annual minimum load is approximately 25% of the annual peak load.
The graph shows a sample load curve of megawatts produced over 12 months at a distribution substation. The annual minimum load is approximately 25% of the annual peak load.
FERC SGIP 15% Rule
The Federal Energy Regulatory Commission’s (FERC) Small Generator Interconnection Procedures (SGIP) contains guidelines for interconnection of wholesale distributed generation, including PV of up to 20 megawatts (MW). The SGIP defines three distinct procedures for DG plants that (1) are smaller than 10 kW, (2) have a maximum size of 2 MW, and (3) are no larger than 20 MW. The procedures and study requirements become more complex for larger systems. Because a large percentage of DG PV sizes are smaller than 2 MW, Section 2 of the SGIP describes a fast-track process. If the proposed generator passes a series of 10 screening tests, interconnection proceeds without the need for any supplemental studies. The 15%-threshold screen often triggers the requirement for supplemental studies. The specific SGIP language states:
2.2.1.2. For interconnection of a proposed Small Generating Facility to a radial distribution circuit, the aggregated generation, including the proposed Small Generating Facility, on the circuit shall not exceed 15% of the line section annual peak load as most recently measured at the substation.
Most DG proposed projects are not wholesale in nature, but are commercial and residential PV installations. As such, state interconnection rules apply. SGIP language is included in many state procedures that apply to state-jurisdictional installations, and most state rules largely conform to the SGIP series of screening tools, including the 15% rule.
Expanding the “15% Rule”
There are several reasons why the 15% threshold may be considered conservative:
- In practice, minimum load on most line sections occurs at night, when PV system output is non-existent. Realistic daytime minimum load on most distribution circuits would be well above the absolute minimum load. For the example in Figure 1, daytime minimum load, when PV generation capacity becomes significant, is closer to 50% of the annual peak load.
- With present anti-islanding technology, the risk of unintentional islanding is very low, even if PV system capacity matches or exceeds the load in a line section.
- Some argue that the 15% threshold is also useful to account for other potential impacts of DG on distribution circuits, including voltage control and protection coordination. However, recent analysis and field experience suggests that these problems are not a significant concern at 15%-penetration levels. There are numerous examples of line sections with PV-penetration levels well beyond 15% with respect to peak load that have reported no performance impacts.
Presently, the DOE SI team, the National Renewable Energy Laboratory (NREL), and Sandia National Laboratories (SNL) are collaborating with the California Public Utilities Commission (CPUC) and Solar Energy Industries Association (SEIA) to evaluate the technical bases that support interconnection screening criteria, including the 15% threshold, and determine whether revisions are justifiable based on documented industry experience and technical advances. NREL and SNL are leading the technical research, compiling data, and conducting high-penetration PV tests and demonstrations with a goal of presenting a white paper that reinforces a higher, but still safe, DG penetration level than the present 15%.
Finally, strategic stakeholder meetings and workshops began in August, 2011, at the CPUC office in San Francisco, California. Additional meetings will be held in September and November 2011 to discuss the adequacy of existing screening procedures, including the 15% threshold, for wholesale distributed generation. The information for the September and November 2011 meetings will be posted on the DOE High Penetration Solar Portal Webpage.
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