• Medium-voltage electrical system protection

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Learning objectives

  1. Understand overcurrent protection requirements for medium-voltage distribution transformers.
  2. Understand overcurrent requirements for medium-voltage distribution.
  3. Learn about code and standard “minimums” that must be considered in the coordination of MV protective devices.

Until recently, engineers didn’t work too frequently in the design of medium-voltage (MV) systems, mainly because anything over 600 V was primarily handled by the utilities. Exception included heavy electrical users such as government institutions, the mining industry, or industrial sites. However, in the past 15 years, there has been an explosion of MV electrical distribution systems used in large commercial complexes. Many of these complexes also have high-rise components with MV risers servicing unit substations at strategic locations on multiple levels. Another feature of large commercial complexes is the associated central plant function with MV chillers and unit substations.

The focus of this article is on overcurrent protection requirements for MV transformers, and connecting transformers to common MV distribution systems. MV designs are subjective and driven by the application. The intent is to illustrate code and standard “minimums” that must be considered in the coordination of MV protective devices. Sizing MV components such as motors, generators, transformers, wiring systems, the architecture of MV systems, or design of complicated protection schemes such as reclosers, zone interlocks, differential protection, etc., are all beyond the scope of this article.

Fundamental objectives

There are three fundamental objectives to overcurrent protection to include ground fault protection:

1. Safety: Personal safety requirements are met if protective devices are rated to carry and interrupt the maximum available load current as well as withstand the maximum available fault currents. Safety requirements ensure equipment is of sufficient rating to withstand the maximum available energy of the worst-case scenario.

2. Equipment protection: Protection requirements are met if overcurrent devices are set above load operation levels and below equipment damage curves. Feeder and transformer protection is defined by the applicable equipment standards. Motor and generator curves are machine specific and are normally provided in the vendor data submittal packages.

3. Selectivity: Selectively requirements are intended to limit system fault or overload response to a specific area or zone of impact and limit disruption of service to the same. Selectivity comprises two major categories:

a. Due to system operation limitations and equipment selection, selectivity is not always possible for non-emergency or optional standby systems.

b. NFPA 70: National Electrical Code (NEC) requires selectivity for:

i. Article 517.17(C): Hospital Ground-Fault Selectivity

ii. Article 700.27: Emergency Systems Coordination

iii. Article 701.27: Legally Required Standby Systems Coordination

Exception: NEC Article 240.4A and 695 allow conductors to be without overload protection where circuit interruption would create a hazard, such as fire pumps. Short-circuit protection is still required.

MV definition

MV is a term used by the electrical power distribution industry; however, various definitions exist.

IEEE 141 divides system voltages into “voltage classes.” Voltages 600 V and below are referred to as “low voltage,” voltages of 600 V to 69 kV are referred to as “medium voltage,” voltages of 69 kV to 230 kV are referred to as “high voltage,” and voltages 230 kV to 1,100 kV are referred to as “extra high voltage” with 1,100 kV also referred to as “ultra-high voltage.”

Per IEEE 141, the following voltage systems are considered MV systems:

Fuse manufacturer Littelfuse states in its literature that “The terms ‘medium voltage’ and ‘high voltage’ have been used interchangeably by many people to describe fuses operating above 600 V.” Technically speaking, “medium voltage” fuses are those intended for the voltage range of 2,400 to 38,000 Vac.

ANSI/IEEE Standard C37.20.2 - Standard for Metal-Clad Switchgear defines MV as 4.76 to 38 kV.

For this article, a good working definition of MV is 1 to 38 kVac as any voltage level above 38 kV is a transmission level voltage versus a distribution level voltage.

MV choice

The choice of service voltage is limited by the voltages the serving utility provides. In most cases, only one choice of electrical utility is available and typically there is limited choice of service voltage. As the power requirements increase, so too does the likelihood that the utility will require a higher service voltage. Typically, if the maximum demand approaches 30 MW, the utility typically may require an on-site substation. The norm, however, is that the utility will give several MV services that the engineer will need to integrate into an owner’s MV distribution system.

In some cases, the utility may provide options for the service voltage. In this case an analysis of options must be conducted to determine the best option for the project. In general, higher service voltage results in more equipment expense. Maintenance and installation costs also increase with higher service voltages. However, for large-scale developments, equipment such as large motors may require a service voltage of 4160 V or higher. Typically, service reliability tends to increase as service voltages increase.

When connecting to an existing utility, the utility typically directs the interconnection requirements including protective device requirements. The utility will include required setting parameters and limitations based on the manufacturer for the protective devices.

MV transformer protection

For discussion purposes, consider an appropriately sized transformer with a known rating. To be clear, a properly sized and rated transformer includes the following features:

  • Adequate capacity for the load to be served
  • Adequate temporary overload capacity (kVA size, or ratings)
  • Primary and secondary voltages properly rated for the electrical distribution system
  • Whether liquid filled or dry type transformers were correctly selected for the application.

The 2011 NEC requires that transformers be protected against overcurrent (NEC Article 450.3). Furthermore, NEC Article 450.3(A) specifically covers transformers over 600 V to include MV transformers.

Figure 4: This illustrates the applicable NEC articles that apply to MV service, feeders, and distribution equipment. Courtesy: JBA Consulting Engineers

Three-phase MV transformers are required to be provided with both primary and secondary overcurrent protective devices (OPD) mainly because the primary and secondary conductors are not considered protected by the primary overcurrent protection. This is especially true for delta primary and wye secondary, where a secondary ground fault may not trip the primary protection. NEC Article 240.21 (C)(1) and NEC Article 450.3(A) validate this statement is true.

Although the primary windings are rated for MV, the designer must choose either fuses or circuit breakers to protect the transformer. As a general rule, 3000 kVA and smaller transformers installed as a stand-alone unit or as unit substations are usually protected by fuses. MV breaker protections are used for transformer sizes greater than 3000 kVA.

Unlike fuses and typical 600 V circuit breakers, MV circuit breakers rely on separate devices such as current transformers (CT), potential transformer (PT), and protective relays to provide the overcurrent protection. The majority of modern relays are multifunction type with the protection referred to by numbers that correlate with the functions they perform. These numbers are based on globally recognized IEEE standards as defined in IEEE Standard C37.2. A sample of a few of the protective function numbers that are used in this standard are shown in Table 1.

Table 1: These numbers are based on globally recognized IEEE standards as defined in IEEE Standard C37.2. Courtesy: JBA Consulting EngineersFigure 3: A single-line drawing illustrates the application of IEEE Standard C37.2 device numbers. Courtesy: JBA Consulting Engineers

Several factors influence the settings of transformer protection:

  • The overcurrent protection required for transformers is considered protection solely for the transformer. Such overcurrent protection does not necessarily protect the primary or secondary conductors, or the equipment connected on the secondary side of the transformer.
  • It is important to note that the overcurrent device on the primary side must be sized based on the transformer’s kVA rating and based on the secondary load to the transformer.
  • Before determining the size or rating of the overcurrent devices, observe that Notes 1 and 2 of NEC Table 450-3(A) permit the rating or setting of primary and/or secondary OPD to be increased to the next higher standard or setting when the calculated value does not correspond to a standard rating or setting.
  • When voltage is switched on to energize a transformer, the transformer core normally saturates, which results in a large inrush current. To accommodate this inrush current, overcurrent protection is typically selected with time-current withstand values of at least 12 times the transformer primary rated current for 0.1 s and 25 times for 0.01 s.
  • Engineers should ensure the protection scheme settings are below the transformer short-circuit damage curves as defined in ANSI C57.109 for oil-filled power transformers and ANSI C57.12.59 for dry-type power transformers.
  • Protective relay curves cannot be used in the same way as low-voltage circuit breaker curves or fuse curves. The protective relay curve only represents the action of a calibrated relay and does not account for the actions of the associated circuit breaker or the accuracy of the current transformers that connect the relay to the monitored circuit.

The curve represents the ideal operation of the relay, and the manufacturing tolerances are not reflected in the curve. To coordinate an overcurrent relay with other protective devices, a minimum time margin must be incorporated between the curves. IEEE Standard 242 Table 15.1 recommended relay time margins are in Table 2.

Fuses and switchgear

E-rated power fuses are typically used in fused switches serving transformers. The purpose of the fuse is to allow for full use of the transformer and to protect the transformer and cables from faults. To accomplish this, the fuse curve should be to the right of the transformer inrush point and to the left of the cable damage curve. Typically, the fuse will cross the transformer damage curve in the long time region (overcurrent region). The secondary main device provides overcurrent protection for the circuit. “E” fuse ratings should always be greater than the transformer full load amps (FLA). The cable damage curve must be above the maximum fault current at 0.01 s.

For transformers 3 MVA and less, standard overcurrent protection schemes for MV switchgear breakers should include an instantaneous and overcurrent combination relay (device 50/51). For transformers greater than 5 MVA, protection schemes become more complex. IEEE device numbers from IEEE C37.2 are used to outline the protection scheme. Transformer MV breakers may include the following protective device numbers:

In MV systems, current transformers (CTs) connect protective or metering devices. CTs interface the electronic device and the MV primary system. The MV primary system voltage and current levels are dangerously high and cannot be connected directly to a relay or meter. The CTs provide isolation from the cable’s high voltage and current levels and translate the primary current to a signal level that can be handled by delicate relays/meters. The rated secondary current is commonly 5 amp, though lower currents such as or 1 amp are not uncommon.

Protective relay’s CTs are expected to deliver about 5 amps or less under healthy load conditions. The current will go to a high value when a fault occurs. Per ANSI C57.13, normal protective CT class secondary should withstand up to 20 times for a short period of times under fault conditions. As a consequence, protective class CTs are accurate enough to drive a set of indication instruments, but will not be good enough for revenue class summation energy metering.

Other factors to consider:

  • CTs for protective relaying should be sized 150% to 200% of the full load amperage (FLA).
  • Unlike low-voltage breakers and fuses, MV circuit breakers do not have fixed trip. Settings do not correspond to those listed as standard in the NEC [NEC Article 240-6(a)].
  • Overcurrent, 51 device, should be set at 100% to 140% of FLA and set below the transformer cable ampacity.
  • Time dial should be set below the transformer damage curve and above the secondary main breaker device.
  • Instantaneous trip, 50 device, should be set below the transformer damage curves, below the cable damage curve at 0.1 set, and approximately 200% of inrush. In addition, the engineer must ensure that the setting does not exceed the maximum available fault current or the instantaneous trip will be rendered worthless.
  • For emergency and legally required standby feeders, NEC Articles 700.26 and 701.26 require the ground fault device shall be an alarm only. For MV systems, this can have significant negative consequences. The installation on neutral grounding resistor should be considered to limit ground fault currents to a safe level for MV generation systems.

Low-voltage switchgear

Industry standard protection schemes for the transformer secondary include a circuit breaker equipped with long-time, short-time, instantaneous, and ground fault functions.

NEC Articles 215.10, 230-95, and 240.13 require ground-fault protection for solidly grounded wye systems of more than 150 V to ground circuits, which includes 277/480 V “wye” connected systems. The ground fault relay or sensor must be set to pick up ground faults that are 1200 amps or more and actuate the main switch or circuit breaker to disconnect all ungrounded conductors of the faulted circuit at a maximum of 1 s.

For hospitals, the substation feeding the distribution system is typically liquid-filled MV primary to 480/277 V secondary transformers connected to service switchboards with both main and feeder breakers. The switchboards shall be equipped with two-level ground-fault detection in accordance with NEC Article 517.17(B). Article 517.17(B) requires that both the main breaker and the first set of OPD downstream from the main have ground fault. Additionally, the ground fault protection shall be selectively coordinated per NEC Article 517.17(C).

For emergency and legally required standby feeders, NEC Articles 700.26 and 701.26 require that the ground fault device shall be alarm only.

For normal side circuits upstream from an automatic transfer switch (ATS), ground fault protection is required per NEC Article 230.95.

Suggested settings are:

  • Device 51 or function long-time pick-up (LTPU): Recommend 100% to 125% of the transformer FLA and set below the transformer and cable damage curves.
  • Long-time delay (LTD), STPU, and short-time delay (STD): Set to coordinate with downstream devices and below the transformer damage curve.
  • Device 50 or instantaneous: Set below cable damage curve and must be above the maximum fault current at the breaker total clear curve.

MV distribution system protection

With protection for MV transformers addressed, the next step is to connect several transformers in a distribution system and to a utility system. In distribution design, the three objectives still apply:

  1. Life safety
  2. Equipment protection
  3. Selectivity.

For example, if the NEC requirements for transformer overcurrent protection are considered without reference to applicable standards and code requirements, the system may address protection of transformers, while other elements of the distribution system (such as the feeders connecting the transformer(s) to the distribution system) may not be protected in accordance with the code.

Article 450 is specific and limited to requirements for the transformer. Ampacity of MV conductors feeding to and extending from the transformer, as well as necessary overcurrent protection of the conductors and equipment, are covered under the following:

  • NEC Article 240-100 and 240-101 applies to MV overcurrent protection over 600 V for feeder and branch circuit.
  • NEC 310.60(C) and Tables 310.77 through 310 list ampacity of MV conductors 2001 to 35000 V.
  • NEC Art 210.9(B) (1) requires the ampacity of the branch circuit conductors shall not be less than 125% of the design potential load.
  • NEC Article 493.30 lists the requirement of metal-enclosed switchgear.
  • NEC Section II (Article 300.31 through 300.50) covers MV wiring methods.
  • NEC Article 310.10 requires shield MV cable for distribution above 2000 V.
  • NEC Article 490.46 MV circuit breaker shall be capable of being lock-out or if installed in a draw-out mechanism, the mechanism shall be capable of being locked.
  • NEC Article 215.2(B) (1) through (3) outlines the size of the circuit grounding conductors.
  • NEC Article 490 covers equipment, over 600 V nominal.

Cold load pickup is defined as follows: Whenever a service has been interrupted to a distribution feeder for 20 minutes or more, it may be extremely difficult to re-energize the load without causing protective relays or fuses to operate. The reason for this is the flow of abnormally high inrush current resulting from the loss of load diversity. High inrush current is caused by:

  • Magnetizing inrush currents to transformers
  • Motor starting currents
  • Current to raise the temperature of lamps and heater elements.

Figure 6: This 2.47 kV to 480 V pad-mounted oil transformer require MV primary and LV secondary basic overcurrent and ground fault protection. Courtesy: JBA Consulting Engineers

Per NEC Art 240.101, the continuous ampere rating of a fuse shall not exceed three times the ampacity of the conductors, and the continuous ampere rating of a breaker shall not exceed six times the ampacity of the conductor.

In industry practice, a feeder relay setting of 200% to 400% of full load is considered reasonable. However, unless precautions are taken, this setting may be too low to prevent relay misoperation on inrush following an outage. Increasing this setting may restrict feeder coverage or prevent a reasonable setting of upstream or source side fuses and protective relays. A satisfactory solution to this problem is the use of extremely inverse relay curves. Extremely inverse relay setting is superior in that substantially faster fault clearing time is achieved at the higher current levels.

The problem of setting ground relay sensitivity to include all faults, yet not trip for heavy-load currents or inrush, is not as difficult as it is for phase relays. If the 3-phase load is balanced, normal ground currents are near zero. Therefore, the ground relay should not be affected by load currents. For balanced distribution systems, the ground relay can be set to pick up as little as 25% of load current. If the 3-phase loads are unbalanced, then the ground relay should be set to pick up at about 50% of load current.

Figure 6: A 12.47 kV service switchgear has incoming utility connection sections, a visible means of disconnect, metering, and fused sections. Courtesy: JBA Consulting Engineers

Under a fault condition, the fault current can easily exceed the capacity of the cable tape shield or concentric neutral ground; hence, a separate ground wire is necessary. For example, Southwire Co. has published tape shields fault current capacity to be 1893 amps at 12.5% tape overlap, and 2045 amps at 25% tape overlap. Most solidly grounded MV distribution system short circuit currents can be well above 10,000 amps. Furthermore, NEC Art 215.2(B) requires a separate ground to handle short circuit currents. The ground conductor is required to be sized per Table 205.122.

For the coordination schemes presented in the examples, the breaker or fuse trip curves did not overlap. In practice, there may be overlapping non-selective protective schemes. In cases involving redundant protective devices, nonselective breaker operation is of little or no concern. Protective devices are redundant—no matter which device opens, the same outage occurs. To improve overall system protection and coordination, redundant devices are intentionally set to overlap (i.e., non-selectivity coordinate with one another).

For MV systems that are more complicated, a system protection engineer should be consulted.

Leslie Fernandez is senior project engineer, electrical at JBA Consulting Engineers. He has more than 28 years of engineering and design and field experience that includes MV distribution systems for military, mining, tunneling, food manufacturing, power production facilities, high-rise facilities, and casino resort complexes.

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