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Line Protection

Line Protection With Distance Relays

Distance relaying should be considered when overcurrent relaying is too slow or is not selective. Distance relays are generally used for phase-fault primary and back-up protection on subtransmission lines, and on transmission lines where high-speed automatic reclosing is not necessary to maintain stability and where the short time delay for end-zone faults can be tolerated.

Overcurrent relays have been used generally for ground-fault primary and back-up protection, but there is a growing trend toward distance relays for ground faults also. Single-step distance relays are used for phase-fault back-up protection at the terminals of generators. Also, single-step distance relays might be used with advantage for back-up protection at power-transformer banks, but at the present such protection is generally provided by inverse-time overcurrent relays. Distance relays are preferred to overcurrent reIays because they are not nearly so much affected by changes in short-circuit-current magnitude as overcurrent relays are, and, hence, are much less affected by changes in generating capacity and in system configuration.

This is because, distance relays achieve selectivity on the basis of impedance rather than current.

The choice between impedance, reactance, or MHO

Because ground resistance can be so variable, a ground distance relay must be practically unaffected by large variations in fault resistance. Consequently, reactance relays are generally preferred for ground relaying. For phase-fault relaying, each type has certain advantages and disadvantages. For very short line sections, the reactance type is preferred for the reason that more of the line can be protected at high speed. This is because the reactance relay is practically unaffected by arc resistance which may be large compared with the line impedance, as described elsewhere in this chapter. On the other hand, reactance-type distance relays at certain locations in a system are the most likely to operate undesirably on severe synchronizing power surges unless additional relay equipment is provided to prevent such operation.

The mho type is best suited for phase-fault relaying for longer lines, and particularly where severe synchronizing-power surges may occur. It is the least likely to require additional equipment to prevent tripping on synchronizing-power surges. When mho relaying is adjusted to protect any given line section, its operating characteristic encloses the least space on the R-X diagram, which means that it will be least affected by abnormal system conditions other than line faults; in other words, it is the most selective of all distance relays.

Because the mho relay is affected by arc resistance more than any other type, it is applied to longer lines. The fact that it combines both the directional and the distancemeasuring functions in one unit with one contact makes it very reliable.

The impedance relay is better suited for phase-fault relaying for lines of moderate length than for either very short or very long lines. Arcs affect an impedance relay more than a reactance relay but less than a mho relay. Synchronizing-power surges affect an impedance relay less than a reactance relay but more than a mho relay. If an impedance-relay characteristic is offset, so as to make it a modified relay, it can be made to resemble either a reactance relay or a mho relay but it will always require a separate directional unit.

There is no sharp dividing line between areas of application where one or another type of distance relay is best suited. Actually, there is much overlapping of these areas. Also, changes that are made in systems, such as the addition of terminals to a line, can change the type of relay best suited to a particular location. Consequently, to realize the fullest capabilities of distance relaying, one should use the type best suited for each application. In some cases much better selectivity can be obtained between relays of the same type, but, if relays are used that are best suited to each line, different types on adjacent lines have no appreciable adverse effect on selectivity.

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UPS design criteria and selection

UPS design criteria and selection

An UPS system is an alternate or backup source of power with the electric utility company being the primary source. The UPS provides protection of load against line frequency variations, elimination of power line noise and voltage transients, voltage regulation, and uninterruptible power for critical loads during failures of normal utility source. An UPS can be considered a source of standby power or emergency power depending on the nature of the critical loads. The amount of power that the UPS must supply also depends on these specific needs.

These needs can include emergency lighting for evacuation, emergency perimeter lighting for security, orderly shut down of manufacturing or computer operations, continued operation of life support or critical medical equipment, safe operation of equipment during sags and brownouts, and a combination of the preceding needs.

The UPS selection process involves several steps as discussed briefly here.

Determine need

Prior to selecting the UPS it is necessary to determine the need. The types of loads may determine whether local, state, or federal laws mandate the incorporation of an UPS. An UPS may be needed for a variety of purposes such as lighting, startup power, transportation, mechanical utility systems, heating, refrigeration, production, fire protection, space conditioning, data processing, communication, life support, or signal circuits.

Some facilities need an UPS for more than one purpose. It is important to determine the acceptable delay between loss of primary power and availability of UPS power, the length of time that emergency or backup power is required, and the criticality of the load that the UPS must bear. All of these factors play into the sizing of the UPS and the selection of the type of the UPS.

Determine safety

It must be determined if the safety of the selected UPS is acceptable. The UPS may have safety issues such as hydrogen accumulation from batteries, or noise pollution from solid-state equipment or rotating equipment. These issues may be addressed through proper precautions or may require a selection of a different UPS.

Determine availability

The availability of the selected UPS must be acceptable. The criticality of the loads will determine the necessary availability of the UPS. The availability of an UPS may be improved by using different configurations to provide redundancy. It should be noted that the C4ISR facilities require a reliability level of 99.9999 percent.

Determine maintainability

The selected UPS must be maintainable. Maintenance of the unit is important in assuring the unit’s availability. If the unit is not properly cared for, the unit will be more likely to fail. Therefore, it is necessary that the maintenance be performed as required. If the skills and resources required for the maintenance of the unit are not available, it may be necessary to select a unit requiring less maintenance.

Determine if affordable

The selected UPS must be affordable. While this is the most limiting factor in the selection process, cost cannot be identified without knowing the other parameters. The pricing of the unit consists of the equipment cost as well as the operating and maintenance costs. Disposal costs of the unit should also be considered for when the unit reaches the end of its life.

Re-evaluate steps

If these criteria are not met, another UPS system must be selected and these steps re-evaluated.


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Arc-resistant low voltage switchgear

Arc-resistant low voltage switchgear

For years, electrical equipment has been designed to withstand and deal with the issue of bolted faults, where the current spikes to a dangerously high level but is safely interrupted by the protective devices contained in the equipment (breakers, fuses and relays). However, these devices typically do not detect and interrupt dangerous internal arcing faults, which have a lower current level, but can generate a far more dangerous scenario for operating personnel.

Arc faults can be caused by a breakdown of insulation materials, objects coming into close proximity with the energized bus assembly, even entry of rodents or other animals into the equipment. The thermal energy created by these events can get as high as 35,000ºF, melting materials and clothing from several feet away. Also consider that the arc blast produced by a lineup of 480 Vac switchgear rated at 85 kA can be equivalent to 20.7 lbs of TNT!


So, what is the solution?

Eaton’s solution: arc-resistant low voltage switchgear

Eaton introduces the addition of an ANSI Type 2 arc-resistant low voltage switchgear offering to its current product line. This is the latest release in arc-safe equipment from Eaton’s Electrical Sector. The arc-resistant low voltage switchgear protects operating and maintenance personnel from dangerous arcing faults
by redirecting or channeling the arc energy out the top of the switchgear, regardless of the origination location of the arc.

Eaton’s arc-resistant low voltage switchgear has been successfully tested to ANSI C37.20.7 at KEMA-Powertest, and has been ULT witnessed and certified.

Standard features
  • Ratings:
    • Up to 100 kA short circuit at 508 Vac maximum and up to 85 kA short circuit at 635 Vac maximum
    • Up to 10 kA horizontal main bus continuous current
    • Up to 5 kA vertical bus continuous current
    • MagnumE DS power circuit breaker frame ratings between 800A and 6000A
  • ANSI Type 2 arc-resistant design protects the operator around the entire perimeter of the equipment
  • Floor-to-ceiling height of 10 feet required whether exhausting into a room or through an arc plenum
  • Strengthened one-piece breaker door and latches
  • Dynamic flap system on rear ventilation openings that remain open under normal operating conditions, but close during an arcing event to prevent dangerous gasses from escaping
  • Patented bellows design allowing drawout of breaker into the disconnected position with the door closed, while simultaneously protecting the operator from any dangerous gasses during an arc event
  • Patented venting system that directs arc gasses out the top of the enclosure, regardless of the arc origination location
  • Up to four-high breaker configuration with no additional layout restrictions
  • Strengthened side and rear panels with standard split rear covers for cable access
  • NEMAT 1 enclosure, with either top or bottom cable or bus duct entry
  • Cable compartment floor plates


Optional features
  • Zone selective interlocking protection
  • ANSI Type 2B arc-resistant design protects the operator even with the low voltage instrument compartment door open
  • Arcflash Reduction Maintenance SystemE
  • Safety shutters
  • One-piece hinged and bolted rear panel
  • Insulated bus
  • Vented bus/cable compartment barrier
  • Cable compartment segregation barrier



  • Superior protection against arcs in breaker, bus or cable compartments
  • No increase in footprint over regular Magnum DS switchgear
  • Closed door racking
  • UL 1558 and UL 891
  • ANSI C37.20.1, ANSI C37.13, ANSI C37.51 and ANSI C37.20.7
  • CSAT standard—CSA C22.2 No. 31-04
  • Third-party (UL/CSA) witness tested
  • Seismic certification 2006-IBC

Testing procedures were completed per ANSI C37.20.7 standards with arcs initiated in:

  • Breaker compartment
  • Vertical and horizontal bus
  • Cable termination compartments

Additionally, the tested arc duration was up to the full 0.5 seconds recommended by ANSI C37.20.7, with no dependence on the tripping speed of an upstream breaker.

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ABB Feeder Protection REF615 ANSI

ABB Feeder Protection REF615 ANSI

The REF615 is powerful, most advanced and simplest feeder protection relay in its class, perfectly offering time and instantaneous overcurrent, negative sequence overcurrent, phase discontinuity, breaker failure and thermal overload protection. The relay also features optional high impedance fault (HIZ) and sensitive earth fault (SEF) protection for grounded and ungrounded distribution systems. Also, the relay incorporates a flexible three-phase multi-shot auto-reclose function for automatic feeder restoration in temporary faults on overhead lines. Enhanced with safety options, the relay offers a three-channel arc-fault detection system for supervision of the switchgear circuit breaker, cable and busbar compartments.

The REF615 also integrates basic control functionality, which facilitates the control of one circuit breaker via the relay’s front panel human machine interface (HMI) or remote control system. To protect the relay from unauthorized access and to maintain the integrity of information, the relay has been provided with a four-level, role-based user authentication system, with individual passwords for the viewer, operator, engineer and administrator level. The access control system applies to the front panel HMI, embedded web browser based HMI and the PCM600 relay setting and configuration tool.

Standardized communication

REF615 supports the new IEC 61850 standard for inter-device communication in substations. The relay also supports the industry standard DNP3.0 and Modbus® protocols.

The implementation of the IEC 61850 substation communication standard in REF615 encompasses both vertical and horizontal communication, including GOOSE messaging and parameter setting according to IEC 61850-8-1. The substation configuration language enables the use of engineering tools for automated configuration, commissioning and maintenance of substation devices.

Bus protection via GOOSE

The REF615 IEC 61850 implementation includes GOOSE messaging for fast horizontal relay-to-relay communication. Applying GOOSE communication to the REF615 relays of the incoming and outgoing feeders of a substation, a stable, reliable and high-speed bus protection system can be realized. The cost-effective GOOSE-based bus protection is obtained just by configuring the relays and the operational availability of the protection is assured by continuous supervision of the protection relays and their GOOSE messaging over the station communication network.

Costs are reduced since no separate physical input and output hard-wiring is needed for horizontal communication between the relays.

Bus protection via GOOSE

Bus protection via GOOSE

Pre-emptive condition monitoring

For continuous knowledge of the operational availability of the REF615 features, a comprehensive set of monitoring functions to supervise the relay health, the trip circuit and the circuit breaker health is included. The breaker monitoring can include checking the wear and tear of the circuit breaker, the spring charging time of the breaker operating mechanism and the gas pressure of the breaker chambers. The relay also monitors the breaker travel time and the number of circuit breaker (CB) operations to provide basic information for scheduling CB maintenance.

Rapid set-up and commissioning

Due to the ready-made adaptation of REF615 for the protection of feeders, the relay can be rapidly set up and commissioned, once it has been given the application- specific relay settings. If the relay needs to be adapted to the special requirements of the intended application, the flexibility of the relay allows the relay’s standard signal configuration to be adjusted by means of the signal matrix tool (SMT) included in its PCM600 relay setting and configuration user tool.

By means of Connectivity Packages containing complete descriptions of ABB’s protection relays, with data signals, parameters and addresses, the relays can be automatically configured via PCM600 relay setting and configuration user tool, COM600 Station Automation series devices, or MicroSCADA Pro substation automation system.

Unique draw-out design relay

The draw-out type relay design speeds up installation and testing of the protection. The factory-tested relay units can be withdrawn from the relay cases during factory and commissioning tests. The relay case provides automatic short-circuiting of the CT secondary circuits to prevent hazardous voltages from arising in the CT circuits when a relay plug-in unit is withdrawn from its case.

The pull-out handle locking the relay unit into its case can be sealed to prevent the unit from being unintentionally withdrawn from the relay case.

REF615 highlights

  • Comprehensive overcurrent protection with high impedance fault, sensitive earth fault and thermal overload protection for feeder and dedicated protection schemes
  • Simultaneous DN3.0 Level 2+ and Modbus Ethernet communications plus device connectivity and system interoperability according to the IEC 61850 standard for next generation substation communication
  • Enhanced digital fault recorder functionality including high sampling frequency, extended length of records, 4 analog and 64 binary channels and flexible triggering possibilities
  • High-speed, three-channel arc flash detection (AFD) for increased personal safety, reduced material damage and minimized system down-time
  • Total control of the operational capability of the protection system through extensive condition monitoring of the relay and the associated primary equipment
  • Draw-out type relay unit and a unique relay case design for a variety of mounting methods and fast installation, routine testing and maintenance
  • One single tool for managing relay settings, signal configuration and disturbance handling

Analog inputs

  • Three phase currents: 5/1 A
  • Ground current: 5/1 A or 0.2 A
  • Rated frequency: 60/50 Hz programmable

Binary inputs and outputs

  • Four binary inputs with common ground
  • Two NO double-pole outputs with TCM
  • Two NO single-pole outputs
  • One Form C signal output
  • One Form C self-check alarm output
  • Additional seven binary inputs plus three binary outputs (available as an option)


  • IEC 61850-8-1 with GOOSE messaging
  • DNP3.0 Level 2+ over TCP/IP
  • Modbus over TCP/IP
  • Time synchronization via SNTP (primary and backup servers)
  • Optional serial RS-485 port programmable for DNP3.0 Level 2+ or Modbus RTU

Control voltage

  • Option 1: 48 … 250 V dc, 100 … 240 V ac
  • Option 2: 24 … 60 V dc




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We have updated the electrical engineering software list on our webpage Stručni programi. Two new software are added to the list: Short-Circuit Current Calculator and Group Motor Protection Guide. These software programs are intended to clearly present product data and technical information that will help the end user with design applications. Both softwares belong to Copper Bussmann.

Short-Circuit Current Calculator

Click to enlarge

Click to enlarge

An easy way to calculate prospective short-circuit current levels

The Cooper Bussmann Point-to-Point Short-Circuit Calculator is a simple, easy-to-use program that allows you to calculate prospective short-circuit currents with a reasonable degree of accuracy. These values can be calculated on the load side of a transformer, at the end of a run of cable or at the end of a busway. Calculations can be made for single or three phase systems.

Group Motor Protection Guide

Click to enlarge screensot

Click to enlarge

A quick and easy-to-use program to help you meet group motor protection requirements

The NEC® section 430-53 allows two or more motors, and other loads, to be protected by the same overcurrent protective device when specific requirements are met. The Cooper Bussmann Group Motor Protection Guide program is a quick and easy-to-use program that will tell you if you meet the requirements of group motor protection by asking a series of questions. Once it is determined that you can use group motor protection, you must still meet the group switching requirements of NEC® section 430-112. The Cooper Bussmann Group Motor Protection Guide program will ask another series of questions to see if you meet these requirements.

Both software are available for  download from our webpage Stručni programi.


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Maintenance Of Molded Case Circuit Breakers (MCCB)

Maintenance Of Molded Case Circuit Breakers (MCCB)

The maintenance of circuit breakers deserves special consideration because of their importance for routine switching and for protection of other equipment.

Electric transmission system breakups and equip­ment destruction can occur if a circuit breaker fails to operate because of a lack of preventive maintenance.

The need for maintenance of circuit breakers is often not obvious as circuit breakers may remain idle, either open or closed, for long periods of time. Breakers that remain idle for 6 months or more should be made to open and close several times in succession to verify proper operation and remove any accumulation of dust or foreign material on moving parts and contacts.

Frequency Of Maintenance

Molded case circuit breakers are designed to require little or no routine maintenance throughout their normal life­ time. Therefore, the need for preventive maintenance will vary depending on operating conditions. As an accumulation of dust on the latch surfaces may affect the operation of the breaker, molded case circuit breakers should be exercised at least once per year.

Routine trip testing should be performed every 3 to 5 years.

Routine Maintenance Tests

Routine maintenance tests enable personnel to determine if breakers are able to perform their basic circuit protective functions. The following tests may be performed during routine maintenance and are aimed at assuring that the breakers are functionally operable. The following tests are to be made only on breakers and equipment that are deenergized.

Insulation Resistance Test

A megohmmeter may be used to make tests between phases of opposite polarity and from current-carrying parts of the circuit breaker to ground. A test should also be made between the line and load terminals with the breaker in the open position. Load and line conductors should be dis­ connected from the breaker under insulation resistance tests to prevent test mesurements from also showing resistance of the attached circuit.

Resistance values below 1 megohm are considered unsafe and the breaker should be inspected for pos­ sible contamination on its surfaces.

Milivolt Drop Test

A millivolt drop test can disclose several abnor­ mal conditions inside a breaker such as eroded contacts, contaminated contacts, or loose internal connec­ tions. The millivolt drop test should be made at a nominal direct-current volt­ age at 50 amperes or 100 amperes for large breakers, and at or below rating for smaller breakers. The millivolt drop is compared against manufacturer’s data for the breaker being tested.

Connections Test

The connections to the circuit breaker should be inspected to determine that a good joint is present and that overheating is not occurring. If overheating is indi­ cated by discoloration or signs of arcing, the connections should be re­ moved and the connecting surfaces cleaned.

Overload tripping test

The proper action of the overload tripping components of the circuit breaker can be verified by applying 300 percent of the breaker rated continuous current to each pole. The significant part of this test is the automatic opening of the circuit breaker and not tripping times as these can be greatly affected by ambient conditions and test condi­ tions.

Mechanical operation

The mechanical operation of the breaker should be checked by turning the breaker on and off several times.



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8DN8 switchgear for rated voltages up to 72.5 kV

8DN8 switchgear for rated voltages up to 145 kV

A fundamental feature of Siemens gas-insulated switchgear is the high degree of versatility provided by its modular system. Depending on their respective functions, the components are housed either individually and/or combined in compressed gas-tight enclosures. With a remarkably small number of active and passive modules, all customary circuit variants are possible. Sulphur hexafluoride (SF6) is used as the insulating and arc-quenching medium.
Three-phase enclosures are used for type 8DN8 switchgear in order to achieve extremely low component dimensions. This concept allows a very compact design with reduced space requirement. Aluminium is used for the enclosure. This assures freedom from corrosion and results in low weight of the equipment. The use of modern construction methods and casting techniques allows optimizing the enclosure’s dielectric and mechanical character- istics. The low bay weight ensures minimal floor loading and eliminates the need for complex foundations.

All the modules are connected to one another by means of flanges. The gastightness of the flange connections is assured by proven O-ring seals. Temperature-related changes in the length of the enclosure and installation tolerances are compensated by bellows-type expansion joints. To that end, the conductors are linked by coupling contacts. Where necessary, the joints are accessible via manway openings.

Gas-tight bushings allow subdivision of the bay into a number of separate gas compartments. Each gas compartment is provided with its own gas monitoring equipment, a rupture diaphragm, and filter material. The static filters in the gas compartments absorb moisture and decomposition products. The rupture diaphragms prevent build-up of an im- permissible high pressure in the enclosure. A gas diverter nozzle on the rupture diaphragm ensures that the gas is expelled in a defined direction in the event of bursting, thus ensuring that the operating personnel is not endangered.

Three-phase enclosure allows compact design

Three-phase enclosure allows compact design

8DN8 switchgear parts

8DN8 switchgear parts (click to see large)

Circuit-breaker module

The central element of the gas-insulated switchgear is the three-pole circuit-breaker module enclosure comprising the following two main components:

  • Interrupter unit
  • Operating mechanism

The design of the interrupter unit and of the operating mechanism is based on proven and in most cases identical designs, which have often been applied for outdoor switchgear installations.

Operating mechanism

The spring-stored energy operating mechanism provides the force for opening and closing the circuit-breaker. It is installed in a compact corrosion- free aluminium housing. The closing spring and the opening spring are arranged so as to ensure good visibility in the operating mechanism block. The entire operating mechanism unit is completely isolated from the SF6 gas compartments. Anti-friction bearings and a maintenance-free charging mechanism ensure decades of reliable operation.
Proven design principles of Siemens circuit-breakers are used, such as vibration-isolated latches and load-free decoupling of the charging mechanism. The operating mechanism offers the following advantages:

  • Defined switching position which is securely maintained even if the auxiliary power supply fails
  • Tripping is possible irrespective of the status of the closing spring
  • High number of mechanical operations
  • Low number of mechanical parts
  • Compact design
Three-position switching device


The functions of a disconnector and an earthing switch are combined in a three-position switching device. The moving contact either closes the isolating gap or connects the high-voltage conductor to the fixed contact of the earthing switch. Integral mutual inter- locking of the two functions is achieved as a result of this design, thus obviating the need for providing corresponding electrical interlocking within the switchgear bay. An insulated connection to the fixed contact of the earthing switch is provided outside the enclosure for test purposes. In the third neutral position neither the disconnector contact nor the earthing switch contact is closed. The three poles of a bay are mutually coupled and all the three poles are operated at once by a motor. Force is transmitted into the enclosure via gas-tight rotating shaft glands. The check-back contacts and the on-off indicators are mechanically robust and are connected directly to the operating shaft. Emergency operation by hand is possible. The enclosure can be provided with inspec- tion windows, in the case of which the “On” and “Off” position of all three phases is visible.

Outgoing feeder module

The outgoing feeder module connects the basic bay with various termination modules (for cable termi- nation, overhead line termination and transformer termination). It contains a three-position switching device, which combines the functions of an outgoing feeder disconnector and of a bay-side earthing switch (work-in-progress type). Installation of a high-speed earthing switch and of a voltage transformer is also possible where required. The high-voltage site testing equipment is generally connected to this module.

Busbar module

Connections between the bays are effected by means of busbars. The busbars of each bay are enclosed. Adjacent busbar modules are coupled by means of expansion joints. The module contains a three-position switching device, which combines the functions of a busbar disconnector and of a bay-side earthing switch (work-in-progress type).

Bus sectionalizers

Bus sectionalizers are used for isolating the busbar sections of a substation. They are integrated in the busbar in the same manner as a busbar module. The module contains a three-position switching device, which combines the functions of a bus sectionalizer and of an earthing switch (work-in-progress type).

High-speed earthing switch

The high-speed earthing switch used is of the so-called “pin-type”. In this type of switch, the earthing pin at earth potential is pushed into the tulip-shaped fixed contact. The earthing switch is equipped with a spring-operated mechanism, charged by an electric motor.

Proven switchgear control

All the elements required for control and monitoring are accommodated in a decentralized arrangement in the high-voltage switching devices. The switching device control systems are factory-tested and the switchgear is usually supplied with bay-internal cabling all the way to the integrated local control cubicle. This minimizes the time required for com- missioning and reduces the possibilities of error.
By default, the control and monitoring system is implemented with electromechanical components. Alternatively, digital intelligent control and pro- tection systems including comprehensive diagnos- tics and monitoring functions are available. More detailed information on condition of the substation state permits condition-based maintenance. This consequently reduces life cycle costs even further.

Gas monitoring

Each bay is divided into functionally distinct gas compartments (circuit-breaker, disconnector, voltage transformer, etc.). The gas compartments are con- stantly observed by means of density monitors with integrated indicators; any deviations are indicated
as soon as they arrive at the defined response thresh- old. The optionally available monitoring system includes sensors that allow remote monitoring and trend forecasts for each gas compartment.

Flexible and reliable protection in bay and substation control

Control and feeder protection are generally accom- modated in the local control cubicle, which is itself integrated in the operating panel of the switchgear bay. This substantially reduces the amount of time and space required for commissioning. Alternatively, a version of the local control cubicle for installation separate from the switchgear is available. Thus, different requirements with respect to the arrange- ment of the control and protection components are easy to meet. The cabling between the separately installed local control cubicle and the high-voltage switching devices is effected via coded plugs, which minimizes both the effort involved and the risk of cabling errors.
Of course we can supply high-voltage switchgear with any customary bay and substation control equipment upon request. We provide uniform systems to meet your individual requirements.

Left: Spring-stored energy operting mechanism; Right: Integrated local control cubicle

Left: Spring-stored energy operting mechanism; Right: Integrated local control cubicle

Neutral interfaces in the switchgear control allow interfacing

  • conventional control systems with contactor interlocking and control panel
  • digital control and protection comprising user- friendly bay controllers and substation auto- mation with PC operator station (HMI)
  • intelligent, uniformly networked digital control and protection systems with supplementary monitoring and telediagnostics functions.

Given the wide range of Siemens control and protection equipment, we can provide customized concepts with everything from a single source.

Technical Data
.Switchgear type.8DN8
.Rated voltage.72.5 / 145 kV
.Rated frequency.50 / 60 Hz
.Rated power frequency withstand voltage (1 min).140 / 275 kV
.Rated lightning impulse withstand voltage (1.2/50 μs).325 / 650 kV
.Rated normal current busbar
.Rated normal current feeder
.2500 / 3150 A
.2500 / 3150 A
.Rated short-breaking current.31.5 / 40 kA
.Rated peak withstand current.85 / 108 kA
.Rated short-time withstand current.31.5 / 40 kA
.Leakage rate per year and gas compartment.≤ 0.5 %
.Bay width.650/800/1200 mm
.Height, depth.see typical bay arrangements
.Driving mechanism of circuit-breaker.stored-energy spring
.Rated operating sequence.O-0.3 s-CO-3 min-CO
.CO-15 s-CO
.Rated supply voltage.60 to 250 V DC
.Expected lifetime.> 50 years
.Ambient temperature range.–30 / –25 °C up to +40 °C
.Standards.IEC / IEEE
Operation and maintenance

Siemens gas-insulated switchgear is designed and manufactured so as to achieve an optimal balance of design, materials used and maintenance required. The hermetically-sealed enclosures and automatic monitoring ensure minimal switchgear mainte- nance: The assemblies are practically maintenance- free under normal operating conditions. We re- commend that the first major inspection be carried out after 25 years.


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Grounded or Ungrounded Systems

Designing a quality grounding system is not only for the safety of employees but also provides the protection required for buildings and equipment.

Ungrounded systems may provide greater continuity of operations in the event of a ground fault. However, the second fault will most likely be more catastrophic than a grounded system fault. Whenever ungrounded systems are used in a facility, the maintenance personnel should receive training in how to detect and troubleshoot the first ground on an ungrounded system.

Electrical systems can be operated grounded or ungrounded, depending on the condition of the systems use. Electrical systems are grounded to protect circuits, equipment, and conductor enclosures from dangerous voltages and personnel from electrical shock. See NEC Sections 110-9, 110-10, 230-65, 250-1, and 250-2 that list the requirements to provide this protection.
“Grounded” means that the connection to ground between the service panel and earth has been made. Ungrounded electrical systems are used where the designer does not want the overcurrent protection device to clear in the event of a ground fault.

Ground detectors can be installed per NEC Section 250-5(b) FPN to sound an alarm or send a message to alert personnel that a ground fault has occurred on one of the phase conductors. Ground detectors will detect the presence of leakage current or developing fault current conditions while the system is still energized and operating. By warning of the need to take corrective action before a problem occurs, safe conditions can usually be maintained until an orderly shutdown is implemented.

Grounded Systems

Grounded systems are equipped with a grounded conductor that is required per NEC Section 250- 23(b) to be run to each service disconnecting means. The grounded conductor can be used as a current-carrying conductor to accommodate all neutral related loads. It can also be used as an equipment grounding conductor to clear ground faults per NEC Section 250-61(a).
A network of equipment grounding conductors is routed from the service equipment enclosure to all metal enclosures throughout the electrical system. The equipment grounding conductor carries fault currents from the point of the fault to the grounded bus in the service equipment where it is transferred to the grounded conductor. The grounded conductor carries the fault current back to the source and returns over the faulted phase and trips open the overcurrent protection device.

Note: A system is considered grounded if the supplying source such as a transformer, generator, etc., is grounded, in addition to the grounding means on the supply side of the service equipment disconnecting device per NEC Sections 250-23(a) or 250-26 for seperately derived systems.
The neutral of any grounded system serves two main purposes: (1) it permits the utilization of line- to-neutral voltage and thus will serve as a current-carrying conductor to carry any unbalanced current, and (2) it plays a vital role in providing a low-impedance path for the flow of fault currents to facilitate the operation of the overcurrent devices in the circuit. (See picture below).

Consideration should be given to the sizing of the neutral conductor for certain loads due to the presence of harmonic currents (See NEC Sections 210-4 and 310-10).

A grounded system is equipped with a grounded (neutral) conductor routed between the supply transformer and the service equipment.

A grounded system is equipped with a grounded (neutral) conductor routed between the supply transformer and the service equipment.

Ungrounded Systems

Ungrounded systems operate without a grounded conductor. In other words, none of the circuit conductors of the electrical system are intentionally grounded to an earth ground such as a metal water pipe, building steel, etc. The same network of equipment grounding conductors is provided for ungrounded systems as for solidly grounded electrical systems. However, equipment grounding conductors (EGCs) are used only to locate phase-to-ground faults and sound some type of alarm.

Therefore, a single sustained line-to-ground fault does not result in an automatic trip of the overcurrent protection device. This is a major benefit if electrical system continuity is required or if it would result in the shutdown of a continuous process. However, if an accidental ground fault occurs and is allowed to flow for a substantial time, overvoltages can develop in the associated phase conductors. Such an overvoltage situation can lead to conductor insulation damage, and while a ground fault remains on one phase of an ungrounded system, personnel contacting one of the other phases and ground are subjected to 1.732 times the voltage they would experience on a solidly neutral grounded system. (See picture below).

Note: All ungrounded systems should be equipped with ground detectors and proper maintenance applied to avoid, as far as practical, the overcurrent of a sustained ground fault on ungrounded systems. If appropriate maintenance is not provided for ungrounded systems, a grounded system should be installed to ensure that ground faults will be cleared and the safety of circuits, equipment, and that personnel safety is ensured.

An ungrounded system does not have a grounded (neutral) conductor routed between the supply transformer and the service equipment because the supply transformer is not earth grounded.

An ungrounded system does not have a grounded (neutral) conductor routed between the supply transformer and the service equipment because the supply transformer is not earth grounded.

High impedance grounding

Electrical systems containing three-phase, three-wire loads, as compared to grounded neutral circuit conductor loads, can be equipped with a high-impedance grounded system. High-impedance grounded systems shall not be used unless they are provided with ground fault indicators or alarms, or both, and qualified personnel are available to quickly locate and eliminate such ground faults.

Ground faults must be promptly removed or the service reliability will be reduced. See NEC Section 250-27 for requirements pertaining to installing a high-impedance grounding system. (See picture below).

A high-impedance grounding system has a high-impedance unit, installed between the grounded (neutral) conductor and the grounding electrode conductor, which is used to regulate fault current.

A high-impedance grounding system has a high-impedance unit, installed between the grounded (neutral) conductor and the grounding electrode conductor, which is used to regulate fault current.



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ANSI CODE : 50BF Circuit Breaker Failure

ANSI CODE : 50BF Circuit Breaker Failure

This function is designed to detect the failure of breakers that do not open when a tripping order is sent. The “breaker failure” protection function is activated by an O1 output tripping order received from the overcurrent protection functions (50/51, 50N/51N, 46, 67N, 67). It checks for the disappearance of current during the time interval specified by the time delay T.

It may also take into account the position of the circuit breaker read on the logic inputs to determine the actual opening of the breaker. Wiring a volt-free closed circuit breaker position contact on the “breaker closed” equation editor input can ensure that the protection is effective in the following situations:

  • When 50BF is activated by protection function 50N/51N (set point Is0 < 0.2 In), detection of the 50BF current set point can possibly be not operational.
  • When trip circuit supervision (TCS) is used, the closed circuit breaker contact is short-circuited. Logic input I102 is therefore no longer operational.

Automatic activation of this protection function requires the use of the program logic circuit breaker control function. A specific input may also be used to activate the protection from the equation editor. That option is useful for adding special cases of activation (e.g. tripping by an external protection unit).
The time-delayed output of the protection unit should be assigned to a logic output via the control matrix.
The starting and stopping of the time delay T counter are conditioned by the presence of a current above the set point (I > Is).

Block diagram
Block diagram – 50BF

Block diagram – 50BF

Example of setting

The example below shows how to determine the time delay setting for the 50BF function Overcurrent protection setting: T = inst. Circuit breaker operating time: 60 ms.
Auxiliary relay operating time to open the upstream breaker or breakers: 10 ms.a

Example of setting

Example of setting using SEPAM relay

The time delay for the 50BF function is the sum of the following times: Sepam O1 output relay pick-up time = 10 ms Circuit breaker opening time = 60 ms Overshoot time for the breaker failure function = 20 ms.

To avoid unwanted tripping of the upstream breakers, choose a margin of approximately 20 ms. This gives us a time delay T = 110 ms.


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ANSI Standards For Medium Voltage protection

ANSI Functions For Protection Devices

In the design of electrical power systems, the ANSI Standard Device Numbers denote what features a protective device supports (such as a relay or circuit breaker). These types of devices protect electrical systems and components from damage when an unwanted event occurs, such as an electrical fault.

ANSI numbers are used to identify the functions of meduim voltage microprocessor devices.

ANSI facilitates the development of American National Standards (ANS) by accrediting the procedures of standards developing organizations (SDOs). These groups work cooperatively to develop voluntary national consensus standards. Accreditation by ANSI signifies that the procedures used by the standards body in connection with the development of American National Standards meet the Institute’s essential requirements for openness, balance, consensus and due process.

ANSI standards (protection) – index
Current protection functions
ANSI 50/51 – Phase overcurrentANSI 79 – Reclose the circuit breaker after tripping
ANSI 50N/51N or 50G/51G – Earth fault or sensitive earth faultDirectional current protection
ANSI 50BF – Breaker failureANSI 67 – Directional phase overcurrent
ANSI 46 -Negative sequence / unbalanceANSI 67N/67NC – Directional earth fault
ANSI 49RMS – Thermal overloadANSI 67N/67NC type 1
Directional power protection functionsANSI 67N/67NC type 2
ANSI 32P – Directional active overpowerANSI 67N/67NC type 3
ANSI 32Q/40 – Directional reactive overpowerMachine protection functions
Voltage protection functionsANSI 37 – Phase undercurrent
ANSI 27D – Positive sequence undervoltageANSI 48/51LR/14 – Locked rotor / excessive starting time
ANSI 27R – Remanent undervoltageANSI 66 – Starts per hour
ANSI 27 – Phase-to-phase undervoltageANSI 50V/51V – Voltage-restrained overcurrent
ANSI 59 – Phase-to-phase overvoltageANSI 26/63 – Thermostat, Buchholz, gas, pressure, temperature detection
ANSI 59N – Neutral voltage displacementANSI 38/49T – Temperature monitoring by RTD
ANSI 47 – Negative sequence voltageFrequency protection functions
ANSI 81H – Overfrequency
ANSI 81L – Underfrequency
ANSI 81R – Rate of change of frequency (ROCOF)

Current protection functions

ANSI 50/51 – Phase overcurrent

Three-phase protection against overloads and phase-to-phase short-circuits.
ANSI index ↑

ANSI 50N/51N or 50G/51G – Earth fault

Earth fault protection based on measured or calculated residual current values:

  • ANSI 50N/51N: residual current calculated or measured by 3 phase current sensors
  • ANSI 50G/51G: residual current measured directly by a specific sensor

ANSI index ↑

ANSI 50BF – Breaker failure

If a breaker fails to be triggered by a tripping order, as detected by the non-extinction of the fault current, this backup protection sends a tripping order to the upstream or adjacent breakers.
ANSI index ↑

ANSI 46 – Negative sequence / unbalance

Protection against phase unbalance, detected by the measurement of negative sequence current:

  • sensitive protection to detect 2-phase faults at the ends of long lines
  • protection of equipment against temperature build-up, caused by an unbalanced power supply, phase inversion or loss of phase, and against phase current unbalance

ANSI index ↑

ANSI 49RMS – Thermal overload

Protection against thermal damage caused by overloads on machines (transformers, motors or generators).
The thermal capacity used is calculated according to a mathematical model which takes into account:

  • current RMS values
  • ambient temperature
  • negative sequence current, a cause of motor rotor temperature rise

ANSI index ↑



Automation device used to limit down time after tripping due to transient or semipermanent faults on overhead lines. The recloser orders automatic reclosing of the breaking device after the time delay required to restore the insulation has elapsed. Recloser operation is easy to adapt for different operating modes by parameter setting.
ANSI index ↑

Directional current protection

ANSI 67N/67NC type 1
ANSI 67 – Directional phase overcurrent

Phase-to-phase short-circuit protection, with selective tripping according to fault current direction. It comprises a phase overcurrent function associated with direction detection, and picks up if the phase overcurrent function in the chosen direction (line or busbar) is activated for at least one of the 3 phases.
ANSI index ↑

ANSI 67N/67NC – Directional earth fault

Earth fault protection, with selective tripping according to fault current direction.
3 types of operation:

  • type 1: the protection function uses the projection of the I0 vector
  • type 2: the protection function uses the I0 vector magnitude with half-plane tripping zone
  • type 3: the protection function uses the I0 vector magnitude with angular sector tripping zone

ANSI index ↑

ANSI 67N/67NC type 1

Directional earth fault protection for impedant, isolated or compensated neutralsystems, based on the projection of measured residual current.
ANSI index ↑

ANSI 67N/67NC type 2

Directional overcurrent protection for impedance and solidly earthed systems, based on measured or calculated residual current. It comprises an earth fault function associated with direction detection, and picks up if the earth fault function in the chosen direction (line or busbar) is activated.
ANSI index ↑

ANSI 67N/67NC type 3

Directional overcurrent protection for distribution networks in which the neutral earthing system varies according to the operating mode, based on measured residual current. It comprises an earth fault function associated with direction detection (angular sector tripping zone defined by 2 adjustable angles), and picks up if the earth fault function in the chosen direction (line or busbar) is activated.
ANSI index ↑

Directional power protection functions

ANSI 32P – Directional active overpower

Two-way protection based on calculated active power, for the following applications:

  • active overpower protection to detect overloads and allow load shedding
  • reverse active power protection:
    • against generators running like motors when the generators consume active power
    • against motors running like generators when the motors supply active power

ANSI index ↑

ANSI 32Q/40 – Directional reactive overpower

Two-way protection based on calculated reactive power to detect field loss on synchronous machines:

  • reactive overpower protection for motors which consume more reactive power with field loss
  • reverse reactive overpower protection for generators which consume reactive power with field loss.

ANSI index ↑

Machine protection functions

ANSI 37 – Phase undercurrent

Protection of pumps against the consequences of a loss of priming by the detection of motor no-load operation.
It is sensitive to a minimum of current in phase 1, remains stable during breaker tripping and may be inhibited by a logic input.
ANSI index ↑

ANSI 48/51LR/14 – Locked rotor / excessive starting time

Protection of motors against overheating caused by:

  • excessive motor starting time due to overloads (e.g. conveyor) or insufficient supply voltage.
    The reacceleration of a motor that is not shut down, indicated by a logic input, may be considered as starting.
  • locked rotor due to motor load (e.g. crusher):
    • in normal operation, after a normal start
    • directly upon starting, before the detection of excessive starting time, with detection of locked rotor by a zero speed detector connected to a logic input, or by the underspeed function.

ANSI index ↑

ANSI 66 – Starts per hour

Protection against motor overheating caused by:

  • too frequent starts: motor energizing is inhibited when the maximum allowable number of starts is reached, after counting of:
    • starts per hour (or adjustable period)
    • consecutive motor hot or cold starts (reacceleration of a motor that is not shut down, indicated by a logic input, may be counted as a start)
  • starts too close together in time: motor re-energizing after a shutdown is only allowed after an adjustable waiting time.

ANSI index ↑

ANSI 50V/51V – Voltage-restrained overcurrent

Phase-to-phase short-circuit protection, for generators. The current tripping set point is voltage-adjusted in order to be sensitive to faults close to the generator which cause voltage drops and lowers the short-circuit current.
ANSI index ↑

ANSI 26/63 – Thermostat/Buchholz

Protection of transformers against temperature rise and internal faults via logic inputs linked to devices integrated in the transformer.
ANSI index ↑

ANSI 38/49T – Temperature monitoring

Protection that detects abnormal temperature build-up by measuring the temperature inside equipment fitted with sensors:

  • transformer: protection of primary and secondary windings
  • motor and generator: protection of stator windings and bearings.

ANSI index ↑

Voltage protection functions

ANSI 27D – Positive sequence undervoltage

Protection of motors against faulty operation due to insufficient or unbalanced network voltage, and detection of reverse rotation direction.
ANSI index ↑

ANSI 27R – Remanent undervoltage

Protection used to check that remanent voltage sustained by rotating machines has been cleared before allowing the busbar supplying the machines to be re-energized, to avoid electrical and mechanical transients.
ANSI index ↑

ANSI 27 – Undervoltage

Protection of motors against voltage sags or detection of abnormally low network voltage to trigger automatic load shedding or source transfer.
Works with phase-to-phase voltage.
ANSI index ↑

ANSI 59 – Overvoltage

Detection of abnormally high network voltage or checking for sufficient voltage to enable source transfer. Works with phase-to-phase or phase-to-neutral voltage, each voltage being monitored separately.
ANSI index ↑

ANSI 59N – Neutral voltage displacement

Detection of insulation faults by measuring residual voltage in isolated neutral systems.
ANSI index ↑

ANSI 47 – Negative sequence overvoltage

Protection against phase unbalance resulting from phase inversion, unbalanced supply or distant fault, detected by the measurement of negative sequence voltage.
ANSI index ↑

Frequency protection functions

ANSI 81H – Overfrequency

Detection of abnormally high frequency compared to the rated frequency, to monitor power supply quality.
ANSI index ↑

ANSI 81L – Underfrequency

Detection of abnormally low frequency compared to the rated frequency, to monitor power supply quality. The protection may be used for overall tripping or load shedding. Protection stability is ensured in the event of the loss of the main source and presence of remanent voltage by a restraint in the event of a continuous decrease of the frequency, which is activated by parameter setting.
ANSI index ↑

ANSI 81R – Rate of change of frequency

Protection function used for fast disconnection of a generator or load shedding control. Based on the calculation of the frequency variation, it is insensitive to transient voltage disturbances and therefore more stable than a phase-shift protection function.

In installations with autonomous production means connected to a utility, the “rate of change of frequency” protection function is used to detect loss of the main system in view of opening the incoming circuit breaker to:

  • protect the generators from a reconnection without checking synchronization
  • avoid supplying loads outside the installation.

Load shedding
The “rate of change of frequency” protection function is used for load shedding in combination with the underfrequency protection to:

  • either accelerate shedding in the event of a large overload
  • or inhibit shedding following a sudden drop in frequency due to a problem that should not be solved by shedding.

ANSI index ↑

Related book: Relay selection guide

Link: Register

Autor: Edvard Csanyi, CsanyiGroup


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