Simulating NEC Voltage and Current Values

The 2017 edition of the National Electrical Code introduces alternative methods for deriving maximum voltage and current values for PV power systems. Specifically, new language in sections 690.7 and 690.8 allows licensed professional engineers to use simulation programs to determine these values for PV systems with a generating capacity of 100 kW or greater. In this article, I review the new subsections, provide a detailed case study and consider the potential benefits of calculating maximum voltage or current values based on simulation program results.

Maximum Voltage

The voltage from a PV power source is inversely proportional to temperature, meaning that maximum system voltage is a function of the lowest expected ambient temperature. To account for temperature dependency, since NEC 1999 section 690.7 has included a table with voltage correction factors for crystalline and monocrystalline silicon modules. Since this table is not module specific, its correction factors are inherently conservative.

To better represent module-specific temperature effects, the Code-making panel introduced an allowance in NEC 2008 allowing for maximum voltage calculations based on manufacturer-provided temperature coefficients. Since the minimum expected ambient temperature for most locations occurs before sunrise, this calculation method is also inherently conservative. (See “Array Voltage Considerations,” SolarPro, October/November 2010.)

NEC 2017 includes both of these well-known methods: 690.7(A)(1) details the temperature coefficient–based calculation allowance, and 690.7(A)(2) details the table-based correction factor calculation allowance. What is new is the allowance in 690.7(A)(3): “For PV systems with a generating capacity of 100 kW or greater, a documented and stamped PV system design, using an industry-standard method and provided by a licensed professional electrical engineer, shall be permitted.”

An informational note directs supervising engineers to Sandia National Laboratories’ Photovoltaic Array Performance Model. Simulation programs that include Sandia’s industry-standard calculation method can calculate maximum voltage while accounting for product-specific temperature coefficients as well as site-specific meteorological data. Engineering calculations based on these modeled results should provide a good representation of the maximum voltage in the fielded array.

Maximum Current

PV source- and output-circuit current are both directly proportional to irradiance, meaning that short-circuit current increases or decreases linearly according to changes in irradiance. To account for the effects of high-irradiance conditions, the Code-making panel responsible for NEC 1999 introduced a 125% solar enhancement multiplier for maximum PV source- and output-circuit calculations. This multiplier is very conservative given that elevated irradiance conditions associated with edge-of-cloud or similar effects are unlikely to continue for 3 hours.

While five subsequent Code editions mandated the use of the 125% irradiance multiplier, NEC 2017 allows for two maximum current calculation methods. 690.8(A)(1)(1) details the traditional method, based on a 125% multiplier, to account for high- irradiance conditions. Alternatively, 690.8(A)(1)(2) allows licensed professional engineers to simulate this value for PV systems with a generating capacity of 100 kW or greater. In the latter case, it says: “The calculated maximum current value shall be based on the highest 3-hour current average resulting from the simulated local irradiance on the PV array accounting for elevation and irradiance. The current value used by this method shall not be less than 70 percent of the value calculated using 690.8(A)(1)(1).”

An informational note directs supervising engineers to the Photovoltaic Array Performance Model and notes that the System Advisor Model (SAM) from the National Renewable Energy Laboratory (NREL) uses Sandia’s model. Calculating maximum current values based on simulation program results accounts for system-specific installation variables as well as location-specific weather data. These modeled and averaged results should provide an accurate representation of the actual 3-hour maximum current values in a fielded PV array.

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