Improving arc flash safety through design

Substation project shows pitfalls and possibilities in system

By David B. Durocher, Eaton Corp. April 19, 2011

While a meter with a bit of software and some comms is getting the kudos of the so-called “smart grid” there is a lot more important work going on in the background – like saving workers’ lives through improved electrical workplace safety. This is highlighted in a technical paper by David B. Durocher, Process Industry Department Chair of the IEEE Industry Applications Society and Global Industry Manager at Eaton Corporation.

“As new standards emerge in electrical workplace safety for electrical systems such as NFPA 70E-2009 and IEEE 1584-2002, it is the responsibility of the systems designer to seek out new approaches and solutions that address them,” Durocher said.

These standards address the dangers of arc flash hazards. Arc flash is the result of a rapid release of energy due to an arcing fault between a phase conductor and another phase conductor, neutral conductor or earth. An arcing fault is similar to the arc obtained during electric welding and the fault has to be manually initiated by something creating the path of conduction such as accidental contact of a test probe between an energized conductor and earth or a failure such as an insulation breakdown.

Energy discharge from an arc flash can be significant, resulting in an energy release at temperatures nearing that of the surface of the sun and explosive pressure waves, shrapnel and toxic gasses. “These emerging workplace safety standards focus primarily on quantifying the radiant heat energy, measured in calories/centimeter-squared from an arc flash event.

The NPFA 70E defines 1.2 cal/cm2 as the onset of a second-degree burn, based on exposure to unprotected skin. There is special flame protected clothing referred to as personal protective equipment (PPE) designed to protect workers from the radiant heat energy,” he said.     

“In the environment of emerging codes and standards such as NFPA70E, focused on improved electrical workplace safety and protection from arc flash, the obvious first choice for any power systems designer is to design the hazard out,” he said.

One best practice example of this is a case study described in Durocher’s technical paper, “Considerations In Unit Substation Design To Optimize Reliability And Electrical Workplace Safety,” published and presented at the February 2010 IEEE Electrical Safety Workshop in Memphis, TN and also at the September 2010 IDC Technologies Power System Protection & Electrical Safety Forum in Brisbane, New South Wales Australia.

Substation case study

The paper describes a design team’s decision process in engineering and specifying low-voltage and medium-voltage power distribution unit substations required in construction of a greenfield process manufacturing facility recently commissioned in the United States.

The project design team reviewed legacy unit substation assemblies installed in other existing facilities to determine what design changes might be deployed for the greenfield site prior to construction. Although unit substation designs vary across regions of the world due to local standards, the typical unit substation applied in North American facilities was configured as shown in the Figure 2.

The substation is designed to transform a plant primary medium voltage, shown here at 13.8 kV, to a plant secondary distribution voltage, in this case 480Y/277 volts, while protecting conductors and electrical systems. A 13.8 kV primary metal-enclosed load-break switch with a 125 ampere current-limiting fuse is shown close coupled to a dry-type transformer, which in turn is connected to low-voltage metal-enclosed switchgear with main metering, plus four 1200 ampere low-voltage drawout power circuit breakers.

“The design team realized that traditional substation designs involved some compromise regarding both safety and reliability,” Durocher said.

For instance, in the United States, the National Electrical Code (NEC) Article 240.21(C)2 addressing overcurrent protection states, “a set of conductors feeding a single load … shall be permitted to be connected to a transformer secondary, without overcurrent protection of the secondary…” and “the ampacity of the secondary conductors is not less than the combined calculated loads on the circuits supplied by the secondary conductors.” In addition, Article 450.3 that addresses secondary overcurrent protection of transformers states, “where secondary overcurrent protection is required, the secondary overcurrent device shall be permitted to consist of not more than six circuit breakers or six sets of fuses grouped in one location.”

The impact of these two standards allowed electrical power systems designers to configure unit substations as shown in the figure above with up to six secondary feeder circuit breakers with no secondary main circuit breaker. This design represents a compromise for secondary bus overload protection as well as secondary overcurrent protection. It is clear that the four 1200 ampere feeder breakers each operating at full load could subject the 3200 ampere secondary bus to an overload.

Also, in the event of a 3-phase bolted fault on the secondary bus, the next upstream protective device shown as a 125 ampere current-limiting fuse would need to clear in order to protect the bus. The fuse rating is selected to account for transformer inrush, resulting in a melting time requirement up to 12X the transformer rated primary current for 0.1 seconds. Thus, the fuse is not selected or designed to protect the secondary bus. In the 2000kVA substation shown a 3-phase bolted fault on the secondary bus would result in a secondary fault current in excess of 41,000 amperes but a primary current of less than 1000 amps and a fuse clearing time of more than two seconds.

However, the current magnitude of an arcing fault during an arc-flash event would be much lower. The same 2000kVA substation with a 3-phase arcing fault on the secondary bus at an assumed secondary arcing current of 10,000 results in a primary current of less than 350 amps and a fuse clearing time of nearly 160 seconds.

For this condition, calculations as defined in IEEE 1584-2002 revealed arc flash energies at the secondary switchgear in excess of 700 calories/cm2. These levels are defined as “unapproachable”, where effectively no personal protective equipment (PPE) would be adequate.

Evaluating the hazards

In many existing facilities, unit substation feeder devices were used as a lockout/tagout point while downstream equipment was being serviced or maintained. The elevated arc flash energies made it unsafe to rack-out a secondary feeder breaker while the secondary bus was energized.

In addition to unapproachable arc flash hazards, should a bus fault occur while this assembly was energized, the likely result beyond extremely high arc flash energies would be extensive equipment damage caused by the heat energy developed before the primary fuse would clear. In a process industry environment, this translates to hours or perhaps days of downtime. In the end, the primary fuse in the 13.8kV fused load-break switch is intended to protect the transformer, not the secondary bus.

Adding a secondary main circuit breaker would resolve this issue of protection in some applications. This would in effect protect the secondary bus downstream of the main breaker. However, the bus from the transformer secondary terminals up to the main is still not adequately protected. Durocher said this area of the bus is sometimes referred to as the “fault free zone”.

“I cannot explain the reason for this label, save perhaps that in this area, the design engineer is hopeful that a fault will never occur!” he said. In applications where the primary assembly and transformer are outdoors and cable connected to the secondary switchgear, the secondary bus protection issue becomes more problematic. He said that the secondary conductors could be installed in accordance with the NEC if they were 10 ft or less, but still not be protected from either short circuit or overload.

“Clearly, an opportunity existed for the project design team to consider design alternatives that would offer better performance, both in reliability and workplace safety,” he said. The project team recognized the limits of the legacy system and threw out the “six- feeders-no main” design.

Technologies in use

Three technologies became apparent. These included a 15 kV vacuum primary circuit breaker with a unique integral trip unit; zone selective interlocking, and multiple setting groups – both technologies employed to reduce circuit breaker clearing time in the event of a bolted or arcing fault.

Because the new site required both low-voltage (480Y/277 V secondary) and medium-voltage (4160Y/2400 V secondary) unit substations, the design team decided to move to application of a primary load-break switch over a fixed mounted vacuum circuit breaker at the primary as a standard platform for both low and medium-voltage unit substations.

The close proximity of the vacuum interrupter in the added 13.8 kV vacuum breaker to the transformer primary winding presented a potential issue regarding protection of the transformer primary windings. To reduce transient switching voltages that occur when the vacuum interrupter opens or closes during switching or fault operation, a special resistor-capacitor snubber was designed and installed to protect the transformer.

The new primary assembly called a Medium Voltage Switch over Breaker (MSB) was the basis of design applied to 11 new unit substations installed at the plant site; two medium-voltage unit substations (10 MVA and 5 MVA with a secondary voltage of 4160 V) and nine low-voltage substations (all at 2000 kVA with a secondary voltage of 480Y/277 V).     

Both medium-voltage and low-voltage substations were installed with high resistance earthing systems which eliminated the possibility of a phase to earth fault, further enhancing system safety and reliability.

Figure 3 shows the installed configuration if the MSB applied in a typical low-voltage unit substation. The primary bus is protected by 200:1 current sensors connected on the primary bus to the vacuum circuit breaker integral overcurrent tripping system. In the event of a transformer fault, the sensors detect an overcurrent and the integral overcurrent trip unit opens to clear the fault. Also installed is secondary bus protection via 3200:5 current transformers connected near the transformer secondary terminals.

These are connected to a separate overcurrent phase and ground protective relay, shown as Device 50/51. In the event of a secondary bus fault, the current transformers detect an overcurrent and the overcurrent relay shunt-trips the vacuum circuit breaker on the primary via a Device 86 lock-out relay.

Notice that the settings of the separate overcurrent relay are established to be selectively coordinated with the secondary air-magnetic feeder breakers so that the breaker nearest a downstream fault will trip first. Note also that the separate overcurrent relay is also connected in a zone-selective interlocking (ZSI) scheme with the feeder breakers. In the event of a secondary bus fault, the overcurrent relay will interrogate the trip units of the feeders to determine that the fault is upstream of the feeder breakers, then the relay will trip the main vacuum breaker, ignoring any short-time delay trip setting used for selective coordination. This significantly increases the vacuum breaker clearing time, reducing both the potential for equipment damage during a fault as well as the arc-flash energy.

Other options

An alternate configuration takes advantage of the multiple setting group capability. In this case, secondary bus protection is supported by current sensors connected to the vacuum circuit breaker integral overcurrent trip unit, and primary protection is accomplished through a separate overcurrent relay connected to primary current transformers.

Here, a special arc flash reduction maintenance switch is installed that allows two distinct setting groups for the vacuum breaker integral overcurrent trip system. The normal setting allows for selective coordination with the downstream feeders as before. When maintenance personnel are racking out secondary feeder circuit breakers, the arc flash reduction maintenance switch is set. This causes the integral overcurrent relay to trip on a preset instantaneous overcurrent and trip immediately when a fault current exceeds the preset threshold.   

Using the vacuum circuit breaker integral trip unit to protect the substation secondary bus offers two advantages in system performance. First, in clearing a secondary bus fault, the inherent latency due to the 86 lockout relay and shunt trip are eliminated. Second, using a multiple settings group capability in a maintenance mode further improves the primary breaker clearing time from 5-7 cycles down to 3 cycles.

Both serve to reduce the downstream arc flash energy and potential equipment damage should a bus fault occur. The tradeoff here is of course that maintenance and operations need to embrace this approach and be willing to adopt new lockout/tagout procedures to support this.

Results from this new technology were impressive. Following completion of the arc flash hazard system study for the new facility, the project design team was elated to confirm that the entire site for both medium-voltage and low-voltage systems demonstrated arc flash hazard levels below 8 calories/cm2. This allowed the electrical maintenance personnel to work safely around energized electrical systems in their standard company issued uniforms, PPE designed for arc flash protection up to 8 calories/cm2.  

“Stepping back and looking at the big picture, the systems designer has an onerous responsibility. Design decisions made today will impact cost, safety and serviceability of the installed systems for 40 or 50 years during the useful life for the owner,” Durocher said.

Studies have shown that this cost is an order of magnitude of 7 to 10 times the installed cost of newly installed power distribution equipment. “The work by the project design team in this effort is considered a significant step forward in innovation in unit substation design,” he said. “In design of greenfield projects such as this, industry must continue to increase focus on safety by design as the most effective approach in minimizing electrical hazards while improving system reliability.”

Developments such as those described in this paper and efforts by a recently formed IEEE Working Group P1814 “Recommended Practice for Electrical System Design Techniques to Improve Electrical Safety.” To get involved or for additional information regarding this article and safety initiative, contact the author at DavidBDurocher(at)