Circuit coordination: reliability, personnel safety or both?
As electrical power systems become more complex, system coordination and protection of a facility becomes increasingly important for safe and reliable operation
- Explore a typical electrical system coordination issue.
- Consider a mitigation approach to support both personnel safety and power system reliability.
- Review an example of using electrical power system software to create time current curves and evaluate selective coordination.
As electrical power systems in facilities such as water treatment plants, processing plants, generation stations, industry complexes, hospitals and other facilities expand and become more complex, electrical distribution system protection and coordination studies become increasingly important for both personnel safety and system reliability during normal and abnormal system operations (e.g., electrical faults). The mechanical forces and thermal energy that result from the huge currents that flow in the system during faults can lead to equipment damage, arc blasts or personnel injury if protective devices do not detect faults quickly and isolate the faulted portion of the system.
The electrical power system must be considered a “living” entity that changes significantly over time as equipment is replaced or upgraded, systems are enhanced or utility interconnection parameters change. Therefore, facility circuit protection and coordination should be performed with the actual installed conditions in association with short-circuit and arc flash studies. Minimizing equipment damage, maintaining reliable system operation and assuring maximum personnel safety are the objectives of the protection and coordination, short-circuit and arc flash studies.
However, study results and how they are interpreted and addressed depend upon the operating philosophy of the particular industrial plant, commercial business and their operating requirements.
Circuit protection and selective coordination concept
The main objectives of electrical system protection and selective coordination are to:
- Isolate only the affected portion of a distribution system and minimize the duration of service interruption.
- Minimize equipment damages.
This task is an engineering art that requires knowledge, experience and understanding of codes and standards, and using power system analysis software such as ETAP, EasyPower, SKM PowerTools, PowerWorld, PSS E and CYME. These tools are capable of using time current curves that are provided and tested by manufacturers to evaluate equipment protection and system selectivity. Regardless of the electrical software used, it is important for a facility to have such a model available and regularly maintain it for identifying electrical system protection and coordination limitations and issues and for improving system reliability and personnel safety.
The intent of an overcurrent protective device coordination study is to make sure equipment such as cable, motor, transformer, generator, switchgear or motor control center are properly protected and to maximize selective coordination to allow the various downstream devices to isolate faults without operation of the upstream devices.
The discussion in this article will be limited to facility selective coordination between low-voltage electrical incoming and its feeder and to evaluate possible impacts on other studies, such as arc flash and calculating incident energy.
A unique challenge
The challenge is twofold — minimizing distribution system outages and assuring personnel safety, with priority always given to personnel safety.
How can a facility balance these two objectives? For instance, could the settings of protective devices be adjusted or changed to different types for better system coordination and reliability without compromising the arc flash hazard?
The following schemes and case study illustrate a typical scenario within a facility and the challenges of balancing personnel safety and system reliability.
This facility is powered from a 13.8-kilovolt circuit via a single 2,500 kilovolt-amperes service transformer (13.8:4.16 kilovolt). Two on-site 1,000-kilowatt backup generators provide facility power in the event of a loss of utility source. The 4.16-kilovolt system primarily powers a few large motors along with a 480-volt motor control center (MCC1) via a 1,000 kilovolt-amperes transformer. MCC1 serves a few large low-voltage (LV) motors and two feeders, one powering facility critical loads (i.e., Feeder2-Bus).
The following schemes focus on coordination between Feeder1-CB and Incoming-LV-CB in case of fault on the Feeder1. A simplified electrical distribution system using ETAP when system is fed from utility source is shown in Figure 1.
Based on the as-built breaker settings and coordination study, Feeder1-CB and Incoming-LV-CB are not coordinating in instantaneous region, overlapping, as shown in Figure 2. Therefore, if there is a fault on Feeder1, the incoming breaker may trip first and causes loss of MCC1, including 150-kilovolt-amperes facility critical loads. The circuit breakers sequence of operation indicates incoming breaker will trip first, then Feeder1 breaker.
However, because the instantaneous setting for the incoming breaker is enabled, the resultant incident energy at this location is low, approximately 2.4 cal/cm2 with a fault clearing time of 0.05 seconds (see Figure 3). This scheme will create more safety for personnel who may work on this MCC; however, it sacrifices system reliability with possible loss of the entire MCC and those critical loads.
Should a facility stay with this arrangement?
Facility personnel may decide to look into this noncoordinated system and provide new settings for the incoming breaker, if possible and improve selective coordination between the incoming breaker and feeder, thereby improving system reliability and operation in case of any disturbances on the Feeder1.
One possible option is to disable the incoming breaker instantaneous setting and make proper coordination, as shown in Figure 4. This means feeder breaker TCC curve is below and to the left of incoming breaker TCC curve. An ETAP sequence of operation is used to illustrate this fact, indicating the feeder breaker will trip first. In this scheme, only Feeder1 will be lost and the remaining of the system will stay in operation.
The trade-off for this adjustment provides protective coordination and a more reliable system but higher incident energy at this location, approximately 16 cal/cm2 due to disabling the instantaneous setting and longer fault clearing time, 0.33 seconds (Figure 5). However, this situation will create more personnel safety concerns.
Should a facility stay with this arrangement?
In many facilities, the upstream and downstream low-voltage protective devices may overlap, which is common when both are molded-case circuit breakers. Therefore, there is a chance that the upstream protective device trips first. A MCCB typically does not have an instantaneous time delay to adjust and resolve overlapping issues.
An alternative might be to replace the upstream MCCB with one that has an adjustable trip. This may not be realistic in many cases because of cost. One possible solution is to only replace the protective device with adjustable settings if there is a history of tripping at these locations.
It is possible to achieve both personnel safety (always the priority) and provide selective coordination and reliable operation.
There are several options and techniques; however, in this case, only one technique is discussed, implementing zone-selective interlock. This is a protection scheme used with electronic trip units to minimize the duration of stress on electrical equipment, caused by phase or ground fault. It can also provide selectivity between protective devices.
In this approach:
- The instantaneous setting of the incoming breaker is enabled.
- Feeder1 breaker will trip first by providing restrained time delay (e.g., 250 msec) to incoming breaker and prevents it (by communication, interlocking or wiring) from tripping on instantaneous, which allows for coordination between these two devices if there is a fault on the feeder as shown in Figure 6.
- Lower incident energy at MCC1, approximately 2.4 cal/cm2 due to enabling the instantaneous setting of the incoming breaker and therefore shorter fault clearing time of 0.05 seconds.
Consequently, by combining selective coordination techniques, both main objectives—personnel safety and system reliability—could be achieved. A summary of these schemes is tabulated in Table 1.
In the event of a fault, minimizing equipment damage, maintaining reliable system operation and assuring maximum personnel safety are the objectives of a well-protected and coordinated electrical system. All of the objectives may not always be achievable. A combination of techniques may be required, and that depends on the operating philosophy of the particular industrial plant or commercial business, but personnel safety should never be sacrificed.
Key electrical codes and standards
The following major standards are applicable to performing power system studies such as the load flow, short circuit, protective device coordination, motor starting, harmonic, reliability and arc flash analysis:
- IEEE 141: Recommended Practice for Electric Power Distribution for Industrial Plants (former IEEE Red Book).
- IEEE 242: Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems (former IEEE Buff Book).
- IEEE 399: Recommended Practice for Industrial and Commercial Power Systems Analysis,
- IEEE 1584-2018: IEEE Guide for Performing Arc-Flash Hazard Calculations.
- IEEE 3002.3: IEEE Recommended Practice for Conducting Short-Circuit Studies of Industrial and Commercial Power Systems.
- NFPA 70: National Electrical Code.
- NFPA 70E: Standard for Electrical Safety in the Workplace.