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Faults in an electrical system reduce the line voltage based on the source and fault impedances. In weak systems, even low magnitude faults can depress the voltage below the minimum contactor holding voltage of motor starters.

When a fault occurs on weak systems, the resultant voltage sag may drop out multiple motors within the system. As it is usually a systemic issue, this typically causes a complete loss of the process.

As both the fault tolerance and the system impedances cannot easily be changed, there is no easy solution to holding the bus voltage. Stored energy (such as capacitors or batteries) are also not useful in maintaining the voltage during fault conditions, the only solution to this is to allow the motor to attempt to ride through the fault event. This requires two key aspects: 1. The motor and load train must maintain stability, and 2. The contactor coil must remain energized. For the first consideration, this is often not trivial as the loss of voltage means almost complete loss of driving torque, which depending on the type of load, may trip the system in a very short amount of time. For the second consideration, an alternate voltage source (e.g. auxiliary DC or UPS) is usually used. This also creates another risk, however, as the motor is now susceptible to out-of-phase conditions resulting from upstream reclosing. A properly designed motor protection and control system addressed both of these risks, facilitating a system better able to maintain process continuity under fault conditions.

The above image is a simulation of a 3.0Ω LLG fault within a 4.16kV distribution system.

During energization of a transformer (or multiple transformers in parallel), significant inrush current may flow as a result of the highly non-linear relationship between magnetic field strength and magnetic flux density. This large inrush current (which can approach orders of magnitude similar to fault current) can produce considerable voltage sags.

The voltage sags developed within a power system resulting from transformer inrush can be quite large and may last for as long as several seconds. This long and pronounced reduction in bus voltage can cause the loss of process loads, specifically induction motors.

The mitigation of this issue is very similar, and in most cases identical, as that for bus fault tolerance of motor contactors. 

The above image shows the simulated energization of a 15MVA transformer.

In order to achieve acceptable selective coordination of overcurrent protective devices, a minimum Coordination Time Interval (CTI) is required within the probably fault region, as outlined in IEEE Std 242 (IEEE Buff Book).

When a fault occurs on weak systems, the resultant voltage sag may drop out multiple motors within the system. As it is usually a systemic issue, this typically causes a complete loss of the process.

A balanced approach of overcurrent element setpoint development is taken. The primary goal of most systems is to ensure process continuity. However, where selective coordination is achieved, fast clearing time is sacrificed, which can put personnel safety at risk. By quantifying incident energy risks, as well as bus financial criticality, a right balance can be struck between safety and continuity.

The above plot shows an example Time-Current Characteristic (TCC) Curve illustrating clear miscoordination of all protective devices within the probable fault range (32kA to 56kA).

 Most industrial electrical distribution system loads are comprised of induction motors. Given that induction motors generally operate with a power factor of between 0.86 and 0.92, the facility as a whole will operate at or below this range at the point of utility service (usually referred to as the point of common coupling, or PCC)

Utilities do not want to supply customers with their required reactive power as, among other things, it limits the ability to transfer real power and requires increased ratings of major electrical equipment. Utilities also cannot readily charge customers for supplying them reactive power. As such, most if not all utilities, provide separate power factor charges in addition to the billing of real energy.

There are several ways which an industrial electrical distribution system may increase its power factor at the PCC. These include the use of synchronous machines in place of induction machines, shunt capacitor or filter banks, and the use of voltage source variable frequency drives.

The above formula is an example (from the Alberta Electric System Operator) of a power factor penalty calculation. 

Shunt capacitor and filter banks are used very often within industrial power systems to assist in supporting bus voltages, providing reactive compensation for power factor purposes, and to limit harmonic current penetration into upstream systems.

It is very common to have shunt capacitors or even filter banks applied to a low or medium voltage power system without conducting any type of frequency domain analysis. If a shunt capacitor or filter is applied to a system where a characteristic (resonant) frequency is close to harmonic orders of the system, non-linear loads may excite the shunt device at this mode, producing large current flows and voltage drops across the equipment. 

The solution to these resonance issues is to identify them in the first place. GP Technologies uses EMTP software to develop comprehensive system models with which to conduct frequency-domain analyses. A frequency sweep of the system is conducted, and the resonant modes are identified. Once identified, mitigative action (such as modifying the characteristic frequency of a filter, or removing shunt capacitance) can be taken to move the resonant frequency away from known harmonic sources.

The image above is from a frequency-domain analysis of a large industrial power system with multiple de-tuned filter banks.