Reactive Power Control in Utility-Scale PV: Page 10 of 11
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Ellis and his coauthors note: “The provision of dynamic reactive capability may have cost implications different from that of static reactive capability, and thus should be separately specified.” They continue: “Dynamic reactive capability from [inverters] can be provided almost instantaneously in a manner similar to that of synchronous machines, responding almost instantly (i.e., within a cycle) to system voltage variations, to support the system during transient events, such as short circuits, switching surges, etc. Fixed capacitors or reactors can be used to shift the dynamic reactive capability toward the lagging or leading side, respectively, as needed. If there is inadequate dynamic reactive capability available from the variable generation resources, it may be necessary to supplement the variable generation resources with an SVC or a STATCOM.”
While inverter-based wind power plants are required to provide reactive power capacity at full output, this requirement has not always applied to the PV industry. Ellis and his coauthors note: “In the case of PV, a requirement to maintain reactive power range at full output power represents a change with respect to historical industry practice. This cost impact could be substantial if the PV plant relies on the PV inverters to provide a portion or all of the required plant-level reactive power capability.” To illustrate their point, the authors present a representative transmission-level interconnection and conclude: “In this case the PV plant would not meet the [reactive power] requirement at full output without adding inverter capacity, derating the plant, or installing external reactive power support devices. In order to achieve a power factor range of 0.95 lag to lead at the POI at rated plant output using only the inverters, the total inverter rating would have to increase by as much as 10% considering reactive losses.”
The difference between the manner in which reactive power —and thus voltage—is controlled on the transmission system versus the distribution system leads to distinct differences in transmission and distribution interconnections requirements.
Transmission-level interconnections. The typical requirements for PV generators interconnected into transmission systems originate from FERC Order 2003, otherwise known as the Large Generator Interconnection Agreement (LGIA). According to the LGIA, generators of more than 20 MW must operate according to a voltage schedule and have a 0.95 lag-to-lead power factor capability at rated power. The LGIA models these requirements after traditional synchronous generator capabilities.
Therefore, PV power plants interconnected at the transmission level typically must be able both to operate in voltage control mode and to have a power factor capability of 0.95 lag to lead at the point of interconnection. For the PV power plant to have the required power factor range at the interconnection point, the inverters themselves must have an even wider power factor range. This is due to the reactive losses within the inverter step-up transformers and the substation transformer(s) that step up the ac collection system voltage to the transmission voltage. Because of these two transformer stages, PV inverters may need to operate with a power factor between 0.85 and 0.9 to realize a power factor of 0.95 at the point of interconnection.
To determine the inverters’ utility-required operating power factor, design engineers can conduct a reactive study with power flow modeling software. As part of the impact study process, utilities typically request a collector impedance model and do a similar modeling to determine whether the project can reasonably meet reactive power capability requirements at the real power capacity indicated on the interconnection request.