Impact of Arc Flash Hazards on Medium Voltage Switchgear

K. R. Shah, Life Senior Member, A. Cinsavich, P. De Silva, Member Shah & Associates, Inc.

416 North Frederick Avenue, Gaithersburg, MD 20877

Abstract - This paper discusses the arc flash ramifications associated with the design and selection of medium voltage switchgear. Arc flash hazard / risk categories are determined on the basis of the available bolted fault current at a particular location as well as the protective settings of upstream protective devices. In some instances, the NFPA 70E hazard/risk Category (HRC) at medium voltage switchgear can easily exceed Category 4, for which no safe PPE exists. Proper design considerations, which include an arc flash analysis at the time of design, can provide a switchgear application that can reduce the HRC below Category 4. NEC Article 110.16 presently lacks a provision for such a requirement as a design constraint on new equipment and further lacks a requirement for placement of arc flash warning labels on switchgear. Accounting for arc flash hazards at the design stage can enable the design of a medium voltage switchgear application that is within Category 4 or less. Placement of warning labels on equipment can warn qualified persons of potential arc flash hazards. Large industrial, commercial, and governmental facilities typically receive power from non-dedicated medium voltage distribution feeders. Since such feeders serve multiple customers, the corresponding Utility protective devices may not provide sufficient protection against arc flash hazards on medium voltage switchgear at a customer’s Point of Common Coupling (PCC) or service entry point. In the event of a change in Utility fault duty or a change in Utility protective device settings, the arc flash hazard/risk Category may increase at the customer’s incoming medium voltage service-entry switchgear without the customer’s knowledge. In order to ascertain accurate arc flash hazard assessments at such switchgear, it is imperative that the Utility promptly notifies the customer of a change in the electrical system parameters. It is unrealistic to assume all PCC’s will be hazard/risk Category 4 or less. It is hoped that this paper will prompt the NEC to require (i) that an arc flash analysis be performed at the time of equipment design so that efforts can be made to limit the hazard/risk category to Category 4 or less and (ii) placement of warning labels on switchgear to warn qualified persons of potential arc flash hazards. It is also hoped that this paper will call to attention the need for enacting regulations requiring Utility companies to notify their customers (serviced at medium voltage or above) in the event that the Utility company changes its electrical system parameters. These actions are required to provide and to maintain safe working conditions throughout an electrical distribution system within a plant/facility.

I. INTRODUCTION

Electric Utilities typically supply power to large industrial, commercial, and governmental customers from non-dedicated medium voltage distribution feeders. Medium voltage switchgear up to 35kV, installed in large customer substations,

can be either metal-enclosed using load interrupter fused/nonfused switches or metal-clad using vacuum circuit breakers. In 2002, the NEC incorporated a mandatory rule, Article 110.16 [1] to address field marking of switchboards, panelboards, industrial control panels, meter socket enclosures, and Motor Control Centers (MCCs); in order to warn qualified persons of potential arc flash hazards present during examination, adjustment, servicing, or maintenance of such equipment. Subsequently, NFPA 70E [2] required a flash hazard analysis to protect personnel from the possibility of being injured by an arc flash event. A number of technical papers discuss arc flash calculations and methods of limiting arc flash hazards/risks [3] [4] within facilities for equipment other than a medium voltage switchgear directly connected to the supply Utility feeders. None of the publications discuss the impact of arc flash hazards to be considered during the selection and procurement of medium voltage switchgear directly fed from the Utility’s medium voltage distribution system. Even NEC-2002 and subsequent edition of the NEC, NEC-2005 Article 110.16 [5], do not require that an arc flash analysis be performed prior to the procurement and subsequent installation of any electrical equipment in “non-dwelling occupancies.” It assumes, incorrectly, that once the electrical equipment is installed, field labeling to warn of arc flash hazards will be adequate for safe operation and maintenance of the equipment. This paper discusses the following: (i) three case studies to demonstrate impact of arc flash hazard analysis on proposed/existing medium voltage installations; (ii) the need to promulgate regulations requiring a supplier (Utility company) to give notice of changes in the available fault duty at the point of common coupling (PCC) with a customer’s facility and changes in upstream protective device settings at the Utility; and (iii) suggestions for modifying NEC Article 110.16 to provide mandatory requirements for (a) performing arc flash analysis prior to installation of electric equipment directly connected to the Utility service and (b) field marking of switchgear to warn qualified persons of potential arc flash hazards. II. NATIONAL ELECTRICAL CODE – PROPOSAL FOR CHANGES The recent edition of the National Electrical Code (NEC 2005), Article 110.16 [5] states, “Flash Protection. Switchboards, panelboards, industrial control panels, meter socket enclosures, and motor control centers that are in other

0197-2618/07/$25.00 © 2007 IEEE 2128

than dwelling occupancies and are likely to require examination, adjustment, servicing, or maintenance while energized shall be field marked to warn qualified persons of potential arc flash hazards. The marking shall be located so as to be clearly visible to qualified persons before examination, adjustment, servicing or maintenance of the equipment.” This Article is deficient because it (i) omits switchgear and (ii) does not require that electrical equipment be designed such that it can be operated and maintained using Personal Protective Equipment (PPE) specified on the warning labels placed on the equipment in accordance with NFPA 70E [2]. Field marking on equipment to warn of potential arc flash hazards, after the equipment is installed, does not provide assurance that the equipment can be operated and maintained safely in accordance with the NFPA 70E. In the following, we will discuss three case studies to demonstrate a need for performing arc flash studies at the design stage, to reduce HRC to a level, under the worse case, below Category 4 for which appropriate PPE is available. The case studies were selected to present different approaches, as accepted by the Owners of these facilities, to mitigate the impact of arc flash hazards.

III. CASE STUDY OF A RAW WATER PUMPING STATION SUPPLIED FROM A DISTANT UTILITY SUBSTATION

A. Existing Electrical Distribution System An existing raw water pumping station is being upgraded to accommodate five 4,000 HP pumps with variable frequency drives. The pumping station is fed from a single 33 kV feeder from a Utility owned substation located over 11.5 miles away. This 33 kV feeder supplies power to a number of other large and small customers and is protected by a microprocessor based 50/51 relay. Fig. 1 depicts the simplified single line diagram of the raw water pumping station. B. Arc Flash Analysis An arc flash analysis of the proposed pumping station as depicted in Fig. 1 estimated an incident energy of 34.4 cal/cm2

at the customer’s 33 kV metal-enclosed switchgear. Hazard/Risk Category (HRC) for the 34.4 cal/cm2 incident energy corresponds to Category 4 in accordance with the NFPA 70E [2]. However since the Utility can change its protective relay settings due to changes in their system conditions without notifying the customers of these changes, an arc flash analysis was performed for the following additional two cases: Case 1: Change protective settings by increasing the Utility relay’s time-dial setting as shown in Fig. 2. Case 2: Change protective settings by increasing the Utility relay’s pick-up setting as shown in Fig. 2. The time current curves in Fig. 2 show the added trip delays in clearing faults for both Cases 1 and 2. The increased time to

Fig. 1: Simplified single line diagram – Raw Water Pumping Station Fig. 2: Impact of change in relay settings – Case 1 and Case 2 – Raw Water Pumping Station

2129

clear the faults in both cases resulted in an increase in the incident energy level to 40.1 cal/cm2 for which appropriate PPE is not available. C. Recommended Solution Since the Utility is not required to inform the customer of changes in their protective devices and or settings, a conservative solution was recommended by specifying arc resistant metal-clad switchgear which can be operated from a remote control cabinet located beyond the arc flash boundary. This solution would permit operation of the switchgear breakers without requiring appropriate PPE.

IV. CASE STUDY OF A STATE OWNED FACILITY

A. Existing Electrical Distribution System A State-owned facility is being upgraded to meet increased load demand and to provide reliable power to the critical infrastructure. The facility is supplied by two 33 kV feeders from a Utility substation as depicted in Fig. 3. Each of the 33 kV feeders supply power to multiple customers and each feeder is protected by microprocessor-based 50/51 relays. The available bolted fault current at the state-owned facility is the same for both feeders. However, the relay settings are different for each feeder as shown in Fig. 4.

Fig. 3: Simplified single line diagram – State-owned Facility.

Fig. 4: Time Current Characteristics of two incoming utility feeders

B. Arc Flash Analysis An arc flash analysis of the 33 kV metal-enclosed switchgear busses connected on the Utility Feeders No. 1 and No. 2 estimated incident energy levels of 53 cal/cm2 and 38 cal/cm2, respectively. Since, as shown in Fig. 3, the facility can be operated from Feeder No. 1 by closing the normally open 33 kV tie switch when power from the Feeder No. 2 is unavailable, a worst case incident energy of 53 cal/cm2

persists throughout the 33kV switchgear for which no safe PPE exists [2].

C. State’s Decision Since there is no safe PPE available to perform operation and maintenance activities, the state decided to outsource the operation and maintenance of the metal-enclosed switchgear to the Utility because electric Utilities are exempt from compliance with the NEC, Article 90.2 (B) (5)c [5].

V. CASE STUDY OF A LARGE WATER FILTRATION PLANT

A. Existing Electrical Distribution System A large Water Filtration Plant is fed from two 69 kV transmission feeders from a Utility owned substation. The power is distributed within the plant at 34.5 kV and stepped down to 4.16 kV to feed large motors. Fig. 5 depicts the simplified single line diagram of the plant. The 4.16 kV bus (B-A1) is fed from two separate sources from the customer-owned 69 kV-34.5 kV substation.

2130

Fig. 5 – Simplified single line diagram – Large Water Filtration Plant

B. Arc Flash Analysis As shown in Table I, the incident energy at the 34.5 kV bus (35kV-OVHD-BUS1) was calculated at 262 cal/cm2 for which there is no safe PPE available [2]. To reduce the incident energy below 40 cal/cm2 (HRC<4) and to provide safe operation and maintenance activities including examination, adjustment, and servicing, a new bus differential protection scheme was proposed. As shown in Table II, the bus differential protection will reduce incident energy to 23 cal/cm2 which is classified as HRC = 3 [2] for which suitable PPE exists.

C. Recommended Solution The plant owner accepted a bus differential protection scheme to reduce incident arc flash energy equivalent to HRC=3 at an estimated cost of $800,000. However, until the differential protection scheme is implemented, the recommended compliance strategy was to place warning labels at each equipment location to warn qualified persons from operating the equipment locally while standing in front of it (within the arc flash boundary) and to direct them to operate the breakers from a remote control house in order to provide a safe workplace in accordance with the NFPA 70E [2].

VI. PROMULGATE REGULATIONS TO REQUIRE SUPPLY UTILITIES TO NOTIFY OF CHANGES TO CUSTOMERS

Large customers, after performing arc flash analysis, based on the Utility-furnished available fault current, relay device settings and protective devices, will provide appropriate switchgear type and will install warning labels on the existing and/or future electric equipment. However in the future, when a supply Utility changes its electrical system to meet increased load demand, it may change the fault duty and relay settings on the feeders supplying power to large customers. As a result, the HRC at a customer’s facilities may increase and will require a new arc flash analysis and also require possible changes of (i) the electric equipment directly connected to the Utility, (ii) protection scheme, (iii) relay settings, (iv) warning labels, and (v) PPE. As illustrated in the case study of the Raw Water Pumping Station discussed in Section III, a change in relay settings by the Utility can change HRC from Category 4 to a Category for which no safe PPE exists. If the customer had designed the equipment based on the existing condition, a metal enclosed switchgear and appropriate PPE, HRC=4 would have been sufficient. However, changes in Utility relay settings would require a different design strategy. This could entail changing from metal enclosed switchgear to metal clad switchgear with remote operation capability, applying a different O&M procedure, or by even outsourcing O&M to the Utility as was done by the State owned facility discussed in Section IV. At this time, there is no requirement for the supply Utility to provide updated changes of the available fault duty and relay settings to large customers. To maintain a safe workplace as required by the NFPA 70E and to ensure that the installed equipment and protective scheme can be

2131

modified to provide HRC at least below Category 4, we recommend that National organizations such as IEEE, NFPA, National professional engineering societies, International Brotherhood of Electrical Workers, NETA, independent electrical contractors and others work together to promulgate regulations requiring supply Utilities to notify their customers of changes in the available fault duty at the customer PCC and/or protective device settings at the supply Utility facilities.

VII. CONCLUSION

Each of the three case studies presented in this paper employed a different strategy to comply with the NEC and NFPA 70E, even though NEC Article 110.16 does not require field marking of switchgear to warn qualified persons of potential arc flash hazards. In order to design, maintain, and operate electrical facilities and to provide a safe workplace in accordance with the NFPA 70E, the following modifications and regulatory changes are recommended:

1. Modify NEC Article 110.16 to include a requirement to perform an arc flash hazard analysis during the design stage of switchgear, switchboards, panelboards, industrial control panels, meter sockets enclosures, and motor control centers applications, to ensure that the specified equipment will be in compliance with

the NFPA 70E after installation and provide a safe workplace that is cost effective.

2. Modify NEC Article 110.16 to include a requirement that switchgear be field marked to warn qualified persons of potential arc flash hazards during examination, adjustment, servicing, maintenance, or operation.

3. Promulgate regulations requiring supply Utilities to notify their customers of changes in the available fault duty at the PCC and protective device settings at the supply Utility facilities to ensure a safe workplace as required by the NFPA 70E.

REFERENCES

[1] National Electrical Code, NFPA 70, 2002 Edition. [2] NFPA 70E, “Standard for Electrical Safety in the

Workplace,” 2004 Edition. [3] J.C. Das, “Design Aspects of Industrial Distribution

Systems to Limit Arc Flash Hazard,” IEEE Transactions on Industry Applications, pp 1476, November/December 2005

[4] Tinsley H.W., Hodeker., Graham A.M., “Arc Flash Hazard Calculations – Myths, Facts, and Solutions,” IEEE Industry Applications Magazine, pp. 58, January/February 2007.

[5] National Electrical Code, NFPA 70, 2005 Edition.

TABLE I

TABLE II

Bus Name Protective Bus Remarks Bus Bus Arc Fault Arc Flash Working Incident NFPADevice kV Bolted Arcing Clearing Boundary Distance Energy Hazard / RiskName Fault Fault Time (in) (in) (cal/cm2) Category

(kA) (kA) (sec.)35KV-OVHD-BUS1 67 Relay 34.50 OCBF1, OCBF3, OCBF5, PCBF7 9.09 9.09 0.201 36 38.6

R-CUST1 34.50 OCBF1, OCBF3, OCBF5, PCBF7 4.89 4.89 2.161 36 223531 36 262 Extreme Danger!

35KV-OVHD-BUS2 67 Relay 34.50 OCBF2, OCBF4, OCBF6, PCBF8 9.33 9.33 0.201 36 39.6R-CUST2 34.50 OCBF2, OCBF4, OCBF6, PCBF8 5.18 5.18 1.961 36 215

523 36 254 Extreme Danger!

Bus Name Protective Bus Remarks Bus Bus Arc Fault Arc Flash Working Incident NFPADevice kV Bolted Arcing Clearing Boundary Distance Energy Hazard / RiskName Fault Fault Time (in) (in) (cal/cm2) Category

(kA) (kA) (sec.)35KV-OVHD-BUS1 Differential 34.50 OCBF1, OCBF3, OCBF5, PCBF7 9.09 9.09 0.12 158 36 23 Category 3

35KV-OVHD-BUS2 Differential 34.50 OCBF2, OCBF4, OCBF6, PCBF8 9.33 9.33 0.12 160 36 23.7 Category 3

2132