Available Fault-Current Calculation and Protection
Inside this Article
A short-circuit fault, which is an abnormal condition that occurs when current bypasses the normal load due to unintentional contact either between phases or to ground, is possible in any electrical system. PV power systems are somewhat unusual in that the PV source itself is current limited. However, the potential short-circuit current increases dramatically when you connect a PV system to the grid. In the event of a short circuit in an interactive PV system, circuits designed for 10s or 100s of amps of current may suddenly carry fault currents on the order of 10,000 or 100,000 amps.
If you do not deploy electrical systems with the available fault current in mind, a short-circuit fault could result in a catastrophic explosion or electrical fire. Overcurrent protection devices (OCPDs), of course, are the first line of defense against short-circuit faults. NEC Section 110.10 states: “The overcurrent protection devices, the total impedance, the short-circuit current rating and other characteristics of the circuit to be protected shall be coordinated to permit the circuit protective devices used to clear a fault to do so without extensive damage to the electrical equipment of the circuit.”
Since the 2011 Code cycle, Section 110.24 has required field markings on service equipment that identify the available fault current in multifamily, commercial and industrial applications. NEC 2017 takes this a step further: “The [available fault current] calculation shall be documented and made available to those authorized to design, install, inspect, or operate the system.” To verify that electrical system designers have selected appropriate OCPDs, it is therefore increasingly common for AHJs to require that PV system integrators document both the available fault current and the ampere interrupting capacity of OCPDs in their plan sets.
Available Fault Current
The available fault current is the highest electrical current that can exist in a particular electrical system under short-circuit conditions. The two potential sources of fault current in interactive PV power systems are the inverter and the utility. From a system design point of view, the available fault current from the utility is what matters.
Like the PV power source itself, an interactive inverter is a current-limited device. According to the National Renewable Energy Laboratory (NREL) technical report, “Understanding Fault Characteristics of Inverter-Based Distributed Energy Resources,” independent testing conducted at NREL suggests that “inverters designed to meet IEEE 1547 and UL 1741 produce fault currents anywhere between 2 to 5 times the rated current for 1 to 4.25 milliseconds.” The authors explain: “Inverters do not have a rotating mass component; therefore, they do not develop inertia to carry fault current based on an electromagnetic characteristic.” In effect, this means that fault current from an interactive inverter is insufficient to open OCPDs.
The utility, by comparison, contributes sufficient fault current to not only open OCPDs but also potentially damage electrical equipment. Therefore, one of the first steps in designing an interactive PV system is to determine the available fault current from the utility, as this value will influence, if not drive, equipment selection. This value is primarily a function of the utility transformer—its capacity (kVA), voltage and impedance—that serves the premises wiring.
For existing electrical services, the easiest way to determine the available fault-current value at the transformer or main service is to contact the utility and request this value. Before doing so, be prepared to provide utility representatives with any relevant information, including site address, transformer location and number (if available), distance from transformer to main service, main service size and so forth. In some cases, you can find the available fault current noted on the electrical plans. If new construction plans do not identify this value, contact the project’s electrical engineer of record.
Note that as you get farther away from the utility transformer, the available fault current decreases in proportion to the impedance of the conductors, as well as on the inverter side of a premises-sited transformer. If, for example, you have a step-down transformer between 3-phase 480 Vac inverters and 3-phase 208 Vac premises wiring, then the available fault current invariably will be lower at the inverter OCPDs than at the service point. In this scenario, you can find the available fault current at the inverter output by dividing the full load current on the PV side of the transformer by its impedance, as identified on the equipment nameplate. Assuming you were using a 3-phase 45 kVA transformer with 5% impedance, you would calculate the available fault current (AFC) thus:
AFC = (45,000 VA ÷ (480 Vac x 1.732)) ÷ 0.05 = 1,083 A
Though the effect of conductor impedance is relatively small compared to the standard interrupt ratings, this could make a difference in circumstances that involve long conductor runs, such as an inverter accumulation panel located a good distance away from the main service. In such a scenario, it might make sense to calculate the available fault current at the subpanel, factoring in the effect of conductor impedance, rather than using the value at the main service panel. While calculating fault current after a length of conductor is beyond the scope of this article, Thomas Domitrovich details the process in the IAEI magazine article “Calculating Short-Circuit Current” (May/June 2015).