Protection and Substation Control

Protection and Substation Control

chapter 8

8 Prot otec ecti tion on and and Substation Control General overview Three trends have emerged in the sphere of power automation: distributed intelligent electronic devices (IED’s), open communication and PC-assisted HMI’s. Numerical relays and computerized substation control are now state-of-the-art.

Corporate Network TCP/IP Power system control center Station unit “Full server“

IEC 60870-5-101

Station bus

The multitude of conventional, individual devices prevalent in the past as well as comprehensive parallel wiring are being replaced by a small number of multifunctional devices with serial connections.

HMI

IEC 60870-5-104

Ethernet TCP/IP

Serial Hub IEC 61850

One design for all applications In this respect, Siemens offers a uniform, universal technology for the entire functional scope of power automation equipment, both in the construction and connection of the devices and in their operation and communication. This results in uniformity of design, coordinated interfaces and the same operating concept being established throughout, whether in power system and generator protection, in measurement and recording systems, in substation control and protection or in telecontrol.

Fig. 8/1

The digital SICAM substation control system implements all of the control, measurement and automation functions of a substation. Protective relays are connected serially.

Photo 8/1

Protection and control in medium-voltage substations

All devices are highly compact and immune to interference, and are therefore also suitable for direct installation in switchgear cells. Furthermore, all devices and systems are self-monitoring, which means that previously costly maintenance can be reduced considerably.

8 Prot otec ecti tion on and and Substation Control General overview Three trends have emerged in the sphere of power automation: distributed intelligent electronic devices (IED’s), open communication and PC-assisted HMI’s. Numerical relays and computerized substation control are now state-of-the-art.

Corporate Network TCP/IP Power system control center Station unit “Full server“

IEC 60870-5-101

Station bus

The multitude of conventional, individual devices prevalent in the past as well as comprehensive parallel wiring are being replaced by a small number of multifunctional devices with serial connections.

HMI

IEC 60870-5-104

Ethernet TCP/IP

Serial Hub IEC 61850

One design for all applications In this respect, Siemens offers a uniform, universal technology for the entire functional scope of power automation equipment, both in the construction and connection of the devices and in their operation and communication. This results in uniformity of design, coordinated interfaces and the same operating concept being established throughout, whether in power system and generator protection, in measurement and recording systems, in substation control and protection or in telecontrol.

Fig. 8/1

The digital SICAM substation control system implements all of the control, measurement and automation functions of a substation. Protective relays are connected serially.

Photo 8/1

Protection and control in medium-voltage substations

All devices are highly compact and immune to interference, and are therefore also suitable for direct installation in switchgear cells. Furthermore, all devices and systems are self-monitoring, which means that previously costly maintenance can be reduced considerably.

Protection and Substation Control

Rationalization Rationaliza tion of operation

by means of SCADA-like control and high-performance PC terminals that can all be operated in the same way

Savings in terms of space and costs

by means of integration of many functions into one unit and compact equipment design

Simplified planning and operational reliability

by means of uniform design, coordinated interfaces and universally identical operating software

Efficient parameterization and operation

thanks to PC terminals with uniform operator interfaces

High levels of reliability and availability

by means of type-tested system technology, technology, complete self-monitoring and the use of proven technology – 20 years of practical experience with digital protection, more than 350,00 devices in operation (in 2004) – 15 years of practical experience with substation automation (SINAUT LSA and SICAM), over 3,000 substations in operation (in 2004)

Fig. 8/2 

For the user, the “entire technology from one partner” has many advantages

Entire technology from one partner The Siemens Power Transmission and Distribution Group supplies devices and systems for: C C

C C

C

Power plant protection Substation control / power system control Remote control (RTU’s) Current measurement and recording Measurement and monitoring of power quality

This covers all of the measurement, control, automation and protection functions for substations. Furthermore, our activities cover: C Consulting C Planning C Design C Commissioning and Service

This uniform technology ”from a single source“ saves the customer time and money in the planning, installation and operation of his substations. SIPROTEC protective relays Siemens offers a complete spectrum of multifunctional, numerical relays for all applications in the field of power system and machine protection. Uniform design and a metal-enclosed construction with conventional connection terminals which is free from electromagnetic interference in accordance with public utility requirements assure simple system design and usage just as with conventional relays.

Numerical measurement techniques ensure precise operation and require less maintenance thanks to their continuous self-monitoring capability. The integration of additional protective and other functions, such as real-time operational measurements, event and fault recording, all in one unit economizes on space, configuration and wiring costs. Setting and programming of the devices can be performed through the integral, plain-text, menu-guided operator display or by using the comfortable DIGSI 4® PC software. For communication at the telecontrol or substation control level, devices of the SIPROTEC 4 group can be equipped with exchangeable communications modules. Besides an optimal integration into the SICAM PAS substation control system in compliance with IEC 61850, the following protocols are supported: PROFIBUS FMS, IEC 60870-5-103, PROFIBUS DP, DNP V3.00 and Modbus. Thus, the on-line measurements and fault data recorded in the protective relays can be used for local and remote control or can be transmitted via telephone modem connections to the workplace of the circuit engineer. Siemens supplies individual devices as well as complete protection systems in factory-assembled cabinets. For complex applications, type and design test facilities are available together with extensive network models using the most modern simulation and evaluation techniques.

8

Protection and substation automation

SICAM power automation

SIPROTEC substation protection

SIMEAS power quality

SICAM PAS power automation systems

7SJ4 and 7SJ6 Feeder protection overcurrent/overload relays

SIMEAS R disturbance recorder

SICAM RTU SICAM miniRTU SICAM microRTU Remote terminal units

7SA5 and 7SA6 feeder protection overcurrent/overload relays

SIMEAS Q power quality recorders

7SD5 and 7SD610 power system protection, differential protection and communication

SIMEAS T measuring transducers

7UT6 transformer protection

SIMEAS P power meter

7UM6 generator/motor protection

7SS60 and 7VH60 busbar protection

Fig. 8/3 

Product range for protection and substation control systems by Siemens

Substation control The digital substation control systems of the SICAM family provide all control, measurement and automation functions (e.g. transformer tap changing) required by a switching station. They operate with distributed intelligence. Communication between devices in branch circuits and the central unit is made via fiber-optic connections which are immune to interference. Devices are extremely compact and can be built directly into mediumand high-voltage switchgear.

SICAM PAS engineering tools are based on Microsoft operating systems, and thanks to their Windows look & feel they are easy to use. The PC-based SICAM PAS UI – Configuration software is used for system configuration and parameterization. SICAM PAS UI – Operation and SICAM Value Viewer support the user during configuration and commissioning and provide diagnostic functions for the system in operation. The operator interface is menuguided, with SCADA-comparable functions, that is, with a level of convenience which was previously only available in a power system control center. Optional telecontrol functions can be added to allow coupling of the system to one or more power system control centers.

In contrast to conventional substation control systems, digital technology saves enormously on space and wiring. SICAM systems are subjected to full factory tests and are delivered ready for operation. Furthermore, SICAM PAS has a system-wide time resolution of 1 ms. Due to the special requirements of medium- and high-voltage systems, bay units and I/O modules withstand voltages up to 2 kV.

Protection and Substation Control

Remote Terminal Units

Switchgear interlocking

Siemens RTU’s fulfill all the classic functions of remote measurement and control. Furthermore, they provide comprehensive data pre-processing of operational and fault information, and automating functions that are based on powerful microprocessors.

The distributed substation control system SICAM PAS provides the option to implement bay-specific and ‘inter-bay’ interlocking by means of on-screen graphic planning. The substation topology as well as infeed conditions are taken into consideration. It prevents false switching, thus enhancing the safety of operating personnel and equipment considerably.

In the classic case, connections to the switchgear are made through coupling relays and transducers. This method allows an economically favorable solution when modernizing or renewing control systems in older installations. Alternatively, especially for new installations, direct connection is also possible. Digital protection devices can be connected by serial links through fiber-optic conductors or bus systems.

Power quality (measuring and recording) The SIMEAS®product range offers equipment for the monitoring of power supply quality (harmonic content, distortion factor, peak loads, power factor, etc.), fault recorders (oscillostores), and measuring transducers. Stored data can be transmitted manually or automatically to PC evaluation systems where they can be analyzed by intelligent programs. Expert systems are also applied here. This leads to rapid fault analysis and valuable indicators for the improvement of network reliability.

measuring transducers with analog and digital outputs. Advantages for the user The concept of the “entire technology from one partner” offers the user many advantages: C High-level security for his systems and operational rationalization possibilities C Powerful system solutions with the most modern technology C Compliance with international standards C Integration in the overall system SIPROTEC®– SICAM®– SIMATIC® C Space and cost savings C Integration of many functions into one unit and compact equipment packaging C Simple planning and safe operation C Homogeneous design, matched interfaces and EMI security throughout C Rationalized programming and handling

For local bulk data storage and transmission, the central processor DAKON can be installed at substation level. Data transmission circuits for analog telephone or digital ISDN networks are incorporated as standard. Connection to local or wide-area networks (LAN, WAN) is equally possible. We can also offer the SIMEAS T series of compact and powerful

8

C

C

C C

C

C

C

C

C C

Windows-based PC tools and standardized displays Fast, flexible mounting and reduced wiring Simple, fast commissioning Efficient spare part stocking, high flexibility High-level operational safety and availability Continuous self-monitoring and proven technology: 20 years of digital relay experience (more than 350,000 units in operation) 15 years of digital substation control (more than 3,000 systems in operation) Rapid problem solving Comprehensive support and fast response from local sales and workshop facilities worldwide

Application notes  All devices and systems for protection, metering and control mentioned herein are designed to be used in the arduous environment of electrical substations, power plants and the various industrial application areas. When the devices were developed, special emphasis was placed on the design of electromechanical interference (EMI). The devices are in accordance with IEC 60255 standards. Detailed information is contained in the device manuals.

Reliable operation of the devices is not affected by the usual interference from the switchgear, even when the device is mounted directly in a l owvoltage compartment of a mediumvoltage switchgear panel. It must, however, be ensured that the coils of auxiliary relays located on the same panel, or in the same c ubicle, are fitted with suitable spike-quenching elements (e.g. free-wheeling diodes). When used in conjunction with switchgear for up to 1 kV or above, all external connection cables should be fitted with a screen grounded at both ends and capable of carrying currents. That means that the cross section of the screen should be at least 4 mm 2 for a single cable and 2.5 mm 2 for multiple cables in one cable duct. All equipment proposed in this guide is built up either in enclosures (type 7XP20) or switchgear cabinets with degree of protection IP51 according to IEC 60529: C Protected against access to dangerous parts with a wire C Sealed against dust C Protected against dripping water

Photo 8/2 

Installation of the numerical protection in the door of the low-voltage compartment of a mediumvoltage switchgear panel

Climatic withstand features C

C

Permissible temperature during service –5°C to +55 °C storage –25°C to +55 °C transport –25°C to +70 °C Permissible humidity Mean value per year ≤ 75% relative humidity; on 56 days per year 95% relative humidity; condensation not permissible

We recommend that units be installed in such a way that they are not subjected to direct sunlight, nor to large temperature variations which may give rise to condensation.

Protection and Substation Control

Mechanical stress

Insulation tests

Vibration and shock during  operation C Standards: IEC 60255-21 and IEC 60068-2 C Vibration – sinusoidal IEC 60255-21-1, class 1 10 Hz to 60 Hz: ± 0.035 mm amplitude; IEC 60068-2-6 60 Hz to 150 Hz: 0.5 g acceleration sweep rate 10 octaves/min 20 cycles in 3 orthogonal axes

C

Vibration and shock during  transport  C Standards: IEC 60255-21 and IEC 60068-2 C Vibration – sinusoidal IEC 60255-21-1, class 2 5 Hz to 8 Hz: ± 7.5 mm amplitude; IEC 60068-2-6 8 Hz to 150 Hz: 2 g acceleration sweep rate 1 octave/min 20 cycles in 3 orthogonal axes C Shock IEC 60255-21-2, class 1 IEC 60068-2-27

Standards: IEC 60255-5 – High-voltage test (routine test) 2 kV (rms), 50 Hz – Impulse voltage withstand test (type test) all circuits, class III 5 kV (peak); 1.2/50 µs; 0.5 J; 3 positive and 3 negative shots at intervals of 5 s

C

C

C

Electromagnetic compatibility EU conformity declaration (CE mark)  All Siemens protection and control products recommended in this manual comply with the EMC Directive 99/336/EEC of the Council of the European Community and further relevant IEC 255 standards on electromagnetic compatibility. All products carry the CE mark.

C

C

EMC tests; immunity (type tests) C

C

C

C

Standards: IEC 60255-22 (product standard) EN 50082-2 (generic standard) High frequency IEC 60255-22-1 class III – 2.5 kV (peak); 1 MHz; τ = 15 µs; 400 shots/s; duration 2 s Electrostatic discharge IEC 60255-22-2 class III and EN 61000-4-2 class III – 4 kV contact discharge; 8 kV air discharge; both polarities; 150 pF; R i = 330 ohm High-frequency electromagnetic field, non-modulated; IEC 60255-22-3 (report) class III – 10 V/m; 27 MHz to 500 MHz

High-frequency electromagnetic field, amplitude-modulated; ENV 50140, class III – 10 V/m; 80 MHz to 1,000 MHz, 80%; 1 kHz; AM High-frequency electromagnetic field, pulse-modulated; ENV 50140/ENV 50204, class III – 10 V/m; 900 MHz; repetition frequency 200 Hz; duty cycle 50% Fast transients IEC 60255-22-4 and EN 61000-4-4, class III – 2 kV; 5/50 ns; 5 kHz; burst length 15 ms; repetition rate 300 ms; both polarities; Ri = 50 ohm; duration 1 min Conducted disturbances induced by radio-frequency fields HF, amplitude-modulated ENV 50141, class III – 10 V; 150 kHz to 80 MHz; 80%; 1 kHz; AM Power-frequency magnetic field EN 61000-4-8, class IV – 30 A/m continuous; 300 A/m for 3 s; 50 Hz

EMC tests; emission (type tests) C

C

C

Standard: EN 50081-2 (generic standard) Interference field strength CISPR 11, EN 55011, class A 30 MHz to 100 MHz Conducted interference voltage, aux. voltage CISPR 22, EN 55022, class B – 150 kHz to 30 MHz

8

Instrument transformers

Instrument transformers must comply with the applicable IEC recommendations IEC 60044, formerly IEC 60185 (current transformers) and 186 (potential transformers), ANSI/IEEE C57.13 or other comparable standards. Potential transformers Potential transformers (p.t.) in single or double-pole design for all primary voltages have single or dual secondary windings of 100, 110 or 120 V/ KL 3, with output ratings between 10 and 300 VA, and accuracies of 0.2, 0.5 or 1% to suit the particular application. Current transformers Current transformers (c.t.) are usually of the single-ratio type with wound or bar-type primaries of adequate thermal rating. Single, dual or triple secondary windings of 1 or 5 A are standard. 1 A rating, however, should be preferred, particularly in HV and EHV stations, to reduce the burden of the connecting leads. Output power (rated burden in VA), accuracy and saturation characteristics (accuracylimiting factor) of the cores and secondary windings must meet the particular application.

The current transformer classification code of IEC is used in the following: Measuring cores  They are normally specified with 0.5% or 1.0 % accuracy (class 0.5 M or 1.0 M), and an accuracy limiting factor of 5 or 10. The required output power (rated burden) must be higher than the actually connected burden. Typical values are 5, 10, 15 VA. Higher values are normally not necessary when only electronic meters and recorders are connected. A typical specification could be: 0.5 M 10, 15 VA. Cores revenue metering  In this case, class 0.2 M is normally required. Protection cores  The size of the protection core depends mainly on the maximum shortcircuit current and the total burden (internal c.t. burden, plus burden of connecting leads, plus relay burden). Further, an overdimensioning factor has to be considered to cover the influence of the DC component in the short-circuit current. In general, an accuracy of 1% (class 5 P) is specified. The accuracy limiting factor KSSC should normally be designed so that at least the maximum short-circuit current can be transmitted without saturation (DC component not considered).

This results, as a rule, in rated accuracy limiting factors of 10 or 20 dependent on the rated burden of the current transformer in relation to the connected burden. A typical specification for protection cores for distribution feeders is 5P10, 15 VA or 5P20, 10 VA. The requirements for protective current transformers for transient performance are specified in IEC 60044-6. In many practical cases, the current transformers cannot be designed to avoid saturation under all circumstances because of cost and space reasons, particularly with metal-enclosed switchgear. The Siemens relays are therefore designed to tolerate current transformer saturation to a large extent. The numerical relays proposed in this guide are particularly stable in this case due to their integral saturation detection function. The required current transformer accuracy- limiting factor K’ ssc can be determined by calculation, as shown in Table 8/4. The transient rated dimensioning factor K td depends on the type of relay and the primary DC time constant. For the normal case, with short-circuit time constants lower than 100 ms, the necessary value for K’ ssc can be taken from Table 8/1.

Protection and Substation Control

R’ b + R ct K’ssc Kssc > R b + R ct

Kssc : Factor of the symmetrical rated short-circuit current K’ssc : Rms factor of the symmetrical rated short-circuit current R b : Ohmic burden (rated) R’ b : Connected burden R ct : Resistance of secondary winding And: K’ssc > Ktd  I ssc. max.  I pn

Ktd

=

Minimum K’ssc

Overcurrent protection 7SJ60, 61, 62, 63, 64

=

Transformer protection 7UT6

 I ssc. max.

 I >>-Setting

≥4

≥5

 I pn

= Max. short-circuit current = Rated primary current = Transient dimensioning factor

Optical waveguide line differential protection 7SD52/610

=

Line differential (pilot wire) protection 7SD600

=

, minimum is 20

 I pn

 I scc. max. (external fault)

for T p ≤ 100 ms

 I pn  I scc. max. (external fault)

for T p > 100 ms

 I pn

 I scc. max. (external fault)  I pn

and K’ssc ≥ 30

Current transformer dimensioning formulae

Table 8/1

U K

Relay type

(R b + R ct)  • Isn  • Kssc

and 3

4

 I pn

≤

( K’ssc • I pn) Line-end 1 ( K’ssc • I pn) Line-end 2

≤4 3

1.3

= Nominal secondary current Example: IEC60044: 600/1, 15 VA, 5 P 10, R ct = 4 Ω (15 + 4) • 1 • 10 BS: U K = V = 146 V 1.3 R ct = 4 Ω  I sn

Table 8/2 

 I scc. max. (external fault)

Numerical busbar protection (low-resistance) 7SS5

Distance protection 7SA522, 7SA6

1 2

= a

Current transformer definition

 I scc. max. (external fault)  I pn

 I scc. max. (close-in fault)

≤ 100 Measuring range

T p > 30 ms:

T p < 50 ms:

a=1 b=4

 I pn

a=2 b=5

and

Us.t. max = 20 • 5 A • R b •

R b = b

P b  I sn2

Us.t. max =

Kssc 20

 I scc. max. (line-end fault)  I pn

T p < 200 ms: a=4 b=5

and  I sn = 5 A results in T p : Primary time constant (system time constant)

P b • Kssc

Table 8/4

Current transformer requirements

5A

Example: IEC 60044:

600/5, 5 P 20, 25 VA

ANSI C57.13:

Us.t. max =

Table 8/3 

= b

25 VA • 20 = 5A = 100 V corresponding to Class C100

ANSI definition of current transformers

8

Relay burden

Burden of the connection leads

The current transformer burdens of the numerical relays of Siemens are below 0.1 VA and can therefore be neglected for a practical estimation. Exceptions are the 7SS60 busbar protection (2 VA) and the pilot wire relays, 7SD600 (4 VA).

The resistance of the current loop from the current transformer to the relay has to be considered as follows:

Normally, intermediate current transformers needn't be used any more, as the ratio adaptation for busbar and transformer protection is numerically performed in the relay. Analog static relays in general also have burdens below about 1 VA. Mechanical relays, however, have a much higher burden, up to the order of 10 VA. This has to be considered when older relays are connected to the same current transformer circuit. In any case, the relevant relay manuals should always be consulted for the actual burden values.

R l =

l

A

Assuming:

2 ρ l ohm A

= Length of the single conductor from the current transformer to the relay in m

Specific resistance ρ

Example: Stability test of the 7SS52 numerical busbar protection system

600/1, 5 P 10, 15 VA, R ct = 4 Ohm

l = 50 m 7SS52 A = 6 mm2  I  scc.max. =

= 0.0179 ohm mm2 (copper wire) m = Conductor cross section in mm2

Table 8/5 

Resistance of current loop

 I scc.max.

30 kA

= 30,000 A = 50 600 A

 I pn

According to Table 8/4

K’ssc

>

1 2

R b

=

15 VA = 15 Ω 1 A2

R Relais = 0.1

50 = 25

Ω

2 0.0179 50 = 0.3 Ω 6

R l

=

R’ b

= R l + R Relais = = 0.3 Ω + 0.1 Ω = 0.4 Ω

K’ssc

= =

R ct + R b R ct + R’ b

Kssc =

4 Ω + 15 Ω = 4 Ω + 0.4 Ω

4 Ω + 15 Ω 10 = 43.2 4 Ω + 0.4 Ω

Result: Rating factor K’ssc (43.2) is greater than the calculated value (25). The stability criterion has therefore been met.

Fig. 8/4

Example: stability verification

Protection and Substation Control

8.1 Power System Protection Introduction Siemens is one of the world‘s leading suppliers of protective equipment for power systems. Thousands of relays ensure first-class performance in the transmission and distribution networks on all voltage levels all over the world, in countries of tropical heat and arctic frost. For many years, Siemens has also significantly influenced the development of protection technology. In 1976, the first minicomputer (process-computer)-based protection system was commissioned: A total of 10 systems for 110/20-kV substations were supplied that are still working at their customers' full satisfaction today. In 1985, we were the first to produce a series of fully numerically controlled relays with standardized communication interfaces. Today, Siemens offers a complete program of protective relays for all applications including numerical busbar protection. To date, more than 350,000 numerical protection relays from Siemens are providing successful service, as stand-alone devices in traditional systems or as components of coordinated protection and substation control.

Meanwhile, the innovative SIPROTEC 4 series has been launched, incorporating the many years of operational experience with thousands of relays as well as the awareness of user requirements (power company recommendations). State of the art Mechanical and solid-state (static) relays have been almost completely phased out of our production because numerical relays are now preferred by the users. Advantages C

C

C

C

C

C

Compact design and lower cost due to the integration of many functions into one relay High availability even with less maintenance owing to integrated self-monitoring No drift (ageing) of the measuring characteristics because of their complete digital processing High availability even with less maintenance due to digital filtering and optimized measuring algorithms Many integrated add-on functions, for example for load monitoring and event/fault recording Local operation keypad and display designed to modern ergonomic criteria

Photo 8/3

C

C

SIPROTEC 4 numerical relays by Siemens

Easy and secure reading of information via serial interfaces with a PC, locally or by remote access Possibility to communicate with higher-level control systems using standardized protocols (open communication)

Modern protection management All the functions, for example, of a power system protection scheme can be incorporated in one unit: C Distance protection with associated add-on and monitoring functions C Universal teleprotection interface C Auto-reclose and synchro-check

8

52

21

67N

FL

79

25

SM

ER

FR

BM

85

Serial link to station – or personal computer to remote line end ANSI-No.*) Circuit-breaker 52 Distance protection 21 67N Directional ground-fault protection Distance-to-fault locator FL Autoreclosure 79 Synchro-check 25 Carrier interface (teleprotection) 85 SM Self-monitoring Event recording ER Fault recording FR BM Breaker monitor *) see Table 8/6 cont. Fig. 8/5 

Load monitor

kA, kV, Hz, MW, MVAr, MVA

01.10.93

Fault report Fault record Relay monitor Breaker monitor Supervisory control

Numerical relays, increased availability of information

Protection-related information can be called up on-line or off-line, such as: C Distance to fault C Fault currents and voltages C Relay operation and data (fault-detector pickup, operating times etc.) C Set values C Line load data (kV, A, MW, kVAr) To fulfill vital protection redundancy requirements, only those functions which are interdependent and directly associated with each other are integrated in the same unit. For backup protection, one or more additional units have to be provided.

All relays can stand fully alone. Thus, the traditional protection concept of separate main and alternate protection as well as the external connection to the outdoor switchyard remain unchanged. “One feeder, one relay” concept Analog protection schemes have been engineered and assembled from individual relays. Interwiring between these relays and scheme testing have been carried out manually in the workshop. Data sharing now allows for the integration of several protection tasks into one single numerical relay. Only a small number of external devices may be required for completion of the overall design concept. This

has significantly lowered the costs of engineering, assembly, panel wiring, testing and commissioning. The reliability of the protection scheme has been highly increased. Engineering has moved from schematic diagrams towards a parameter definition procedure. The documentation is provided by the relay itself. Free allocation of LED operation indicators and output contacts provides more application design flexibility.

Protection and Substation Control

Measuring function included The additional transducer was rather used for protecting measuring instruments under system fault conditions. Due to the low thermal withstand capability of the measuring instruments, they could not be connected to the protective current transformer directly. When numerical protection technology is employed, protective current transformers are in many cases accurate enough to take operational measurements. Consequently, additional transducers and measuring instruments are now only necessary where high accuracy is required, e.g. for metering used for electricity bills.

Recording

Personal computer DIGSI

Assigning

Protection

Laptop

DIGSI Recording and confirmation

Online remote data exchange A powerful serial data link provides for interrogation of digitized measured values and other information stored in the protection units, for printout and further processing at the substation or system control level. In the opposite direction, settings may be altered or test routines initiated from a remote control center. For greater distances, especially in outdoor switchyards, fiber-optic cables are preferably used. This technique has the advantage that it is totally unaffected by electromagnetic interference.

to remote control

System level

Substation level

Coordinated protection and control

Modem (option) ERTU

RTU

Data collection device Bay level

52

Offline communication with numerical relays A simple built-in operator keypad which requires no special software knowledge or code word tables is used for parameter input and readout.

PC-aided setting procedure of numerical protection relays

Fig. 8/6 

Relay

Fig. 8/7 

Control

Communication options

8

This allows operator dialog with the protective relay. Answers appear largely in plain text on the display of the operator panel. Dialog is divided into three main stages: C Input, alteration and readout of settings C Testing the functions of the protective device and C Readout of relay operation data for the three last system faults and the auto-reclose counter

Setpoints

The MS Windows-compatible relay operation program DIGSI 4 is available for entering and readout of setpoints and archiving of protection data. The relays may be set in 2 steps. First, all relay settings are prepared in the office with the aid of a local PC and stored on a diskette or the hard disk. On site, the settings can then be downloaded from a PC into the relay. The relay confirms the settings and thus provides an unquestionable record. Vice versa, after a system fault, the relay memory can be uploaded to a PC, and comprehensive fault analysis can then take place in the engineer’s office. Alternatively, the entire relay dialog can be guided from any remote location through a modem-telephone connection (Fig. 8/7).

1,200 flags p. a.

10,000 setpoints

200 setpoints

Modern power system protection management A notebook PC may be used for upgraded protection management.

Relay operations

20 setpoints

1 system approx. 500 relays

1 bay

substation OH line

System-wide setting and relay operation library

1000

1000 1100 1200 1500 280 3900

Fig. 8/9 

system

4 flags

1 substation

Fig.8/8 

300 faults p. a. approx. 6,000 km OHL (fault rate: 5 p. a. and 100 km)

1000

Parameter 1100

Parameter 1100

Line data A 1200

1000

Parameter

Parameter 1100

Line data C

Line data B 1200

O/C Phase settings

O/C Phase 1500settings O/C Ground settings Line data 1200 O/C Phase 1500settings O/C Ground 280 settings Fault recording O/C phase settings 1500 O/C Ground settings 280 Fault recording 3900 Breaker fail O/C earth settings 280 Fault recording 3900 Breaker fail Fault recording 3900 Breaker fail Breaker fail

Alternate parameter groups

D

Protection and Substation Control

Relay data management

Adaptive relaying

Analog distribution-type relays have some 20–30 setpoints. If we consider a power system with about 500 relays, then the number adds up to 10,000 settings. This requires considerable expenditure in setting the relays and filing retrieval setpoints.

Numerical relays now offer secure, convenient and comprehensive adjustment to changing conditions. Adjustments may be initiated either by the relay’s own intelligence or from outside via contacts or serial telegrams. Modern numerical relays contain a number of parameter sets that can be pre-tested during commissioning of the scheme (Fig. 8/9). One set is normally operative. Transfer to the other sets can be controlled via binary inputs or serial data link. There are a number of a pplications for which multiple setting groups can upgrade the scheme performance, for example:

A personal computer-aided man-machine dialog and archiving program, e.g. DIGSI 4, assists the relay engineer in data filing and retrieval.

The program files all settings systematically in substation-feeder-relay order. Corrective rather than preventive maintenance Numerical relays monitor their own hardware and software. Exhaustive self-monitoring and failure diagnostic routines are not restricted to the protective relay itself, but are methodically carried through from current transformer circuits to tripping relay coils. Equipment failures and faults in the current transformer circuits are immediately recorded and signaled. Thus, the service personnel are now able to correct the failure upon occurrence, resulting in a significantly upgraded availability of the protection system.

d) For auto-reclose programs, i.e. instantaneous operation for first trip and delayed operation after unsuccessful reclosure. e) For cold load pickup problems where high starting currents may cause relay operation. f) For ”ring open“ or ”ring closed“ operation.

a) For use as a voltage-dependent control of o/c relay pickup values to overcome alternator fault current decrement to below normal load current when the AVR is not in automatic operation. b) For maintaining short operation times with lower fault currents, e.g. automatic change of settings if one supply transformer is taken out of service. c) For “switch-onto-fault” protection to provide shorter time settings when energizing a circuit after maintenance. The normal settings can be restored automatically after a time delay.

8

8.2 Relay Design and Operation Mode of operation Numerical protective relays operate on the basis of numerical measuring principles. The analog measured values of current and voltage are decoupled electrically from the system's secondary circuits via input transducers (Fig. 8/10). After analog filtering, the sampling and the analog-to-digital conversion take place. The sampling rate is, depending on the different protection principles, between 12 and 20 samples per period. With certain devices (e.g. generator protection) a continuous adjustment of the sampling rate takes place depending on the actual system frequency.

The protection principle is based on a cyclic calculation algorithm, utilizing the sampled current and voltage analog measured values. The fault detection determined by this process must be established in several sequential calculations before protection reactions can follow. A trip command is transferred to the command relay by the processor, utilizing a dual-channel control. The numerical protection concept offers a multitude of advantages, especially with regard to higher security, reliability and user friendliness, such as:

C

C

C

High measurement accuracy: The high utilization of adaptive algorithms produce accurate results even during problematic conditions Good long-term stability: Due to the digital mode of operation, drift phenomena at components due to ageing do not lead to changes in accuracy of measurement or time delays Security against over- and underfunctioning: With this concept, the danger of an undetected defect or malfunction in the device causing protection failure in the event of a line fault is clearly reduced when compared to conventional protection technology. Cyclical and preventive maintenance services have therefore become largely obsolete.

PC interface, substation control interface

Meas. inputs

Current inputs (100 x / N, 1 s)

Input/ output ports

V.24 FO serial interfaces

Input filter

Binary inputs

Alarm relay

Amplifier

Command relay Voltage inputs (140 V continuous)

100 V/1 A, 5 A analog

Fig. 8/10 

A/D converter 0001 0101 0011

10 V analog

Block diagram of numerical protection

Processor system

Memory: RAM EEPROM EPROM

digital

Input/ output units

Input/output contacts

LED displays

Protection and Substation Control

Plausibility check of input quantities e.g. i L1 + i L2 + i L3 = i E u L1 + u L2 + u L3 = u E

Check of analog-to-digital conversion by comparison with converted reference quantities

A D

The integrated self-monitoring system (Fig. 8/11) encompasses the following areas: C Analog inputs C Microprocessor system C Command relays Implemented functions

Microprocessor system

Hardware and software monitoring of the microprocessor system incl. memory, e.g. by watchdog and cyclic memory checks

Relay

Monitoring of the tripping relays operated via dual channels

SIPROTEC relays are available with a variety of protective functions (see relay charts, page 25 cont.). The high processing power of modern numerical devices allow further integration of non-protective add-on functions. The question as to whether separate or combined relays should be used for protection and control cannot be uniformly answered. In transmissiontype substations, separation into independent hardware units is still preferred, whereas on the distribution level, a trend towards higher function integration can be observed. Here, combined feeder relays for protection, monitoring and control are gaining ground (Photo 8/4).

Tripping check or test reclosure by local or remote operation (not automatic)

Fig. 8/11

Self-monitoring system

Photo 8/4

Switchgear with numerical rel ay ( 7SJ 62 ) and tr ad iti onal cont ro l

With the SIPROTEC 4 series (types 7SJ61, 62 and 63), Siemens supports both stand-alone and combined solutions on the basis of a single hardware and software platform. The user can decide within wide limits on the configuration of the control and protection functions in the feeder, without compromising the reliability of the protection functions (Fig. 8/12). Switchgear with combined protection and c ont ro l re lay ( 7S J63 )

8

Busbar 52

7SJ61/62/63/64

Local, remote control Command/checkback Motor control Trip (only 7SJ63/64) monitor

7SJ62/63/64 Measurements during operation

CFC logic

Synchronization (only 7SJ64)

Limit values, mean values, min/max memory

Final OFF

Energy counter values as count pulses

Thermobox connection

Fault Operation Communications Motor protection element modules recording logic Bearing RS232/485/LWL temp. I< Startup time IEC 61850 ICE 60870-5-103 PROFIBUS FMS/DP SwitchLocked DNP3.0 on rotor MODBUS RTU lock

Inrush lock

U, f, P  element

calculated

(only 7SJ64)

Fault detector

Interm. ground fault

Ground fault detection element

Switch failure protection High-imp. Autodiff. reclosure

Fig. 8/12 

Directional element Phase-sequence monitoring

Directional ground fault detection element

SIPROTEC 4 relay types 7SJ61/62/63/64, implemented functions

The following solutions are available within one relay family: C Separate control and protection relays C Protective relays including remote control of the feeder breaker via the serial communication link C Combined feeder relays for protection, monitoring and control

DIGSI 4 Telephone connection

SICAM PAS

IEC 61850 or IEC 60870-5-103 Modem

IEC 6870-5 DIGSI 4

Mixed use of the different relay types is easily possible on account of the uniform operation and communication procedures.

IEC 60870-5-103

Fig. 8/13 

SIPROTEC 4 relays, options for communication

Protection and Substation Control

Integration of relays into substation control Basically, all Siemens numerical relays are equipped with an an i nterface acc. to IEC 60870-5-103 for open communication with substation control systems either by Siemens (SICAM) or by any other supplier. The relays of the latest SIPROTEC 4 series, however, are even more flexible and equipped with several communication options. SIPROTEC 4 relays can still be connected to the SICAM system or to a communications system of another supplier via IEC 60870-5-103. SIPROTEC 4 protection systems and SICAM substation control technology have a uniform design. Communication is based on the PROFIBUS standard. IEC 61850 has been established as a global standard by users and manufacturers. The agreed objective of this standard is to create a comprehensive communications solution for substations. Thus, the user is provided with open communication systems which are based on Ethernet technology. SIPROTEC protective relays and bay control units are the first devices released in mid 2004 which use a communications protocol in compliance with IEC 61850. The station configurator, which is part of the DIGSI 4 operating software, can be used to configure SIPROTEC relays as well as non-Siemens relays via IEC 61850.

1 1 2

2

3

3 4

4

5

6

6

7

1 Large illuminated display 2 Cursor keys 3 LED with reset key Photo 8/5 

7

4 Control (7SJ61/62 uses function keys) 5 Key switches

Front view of the 7SJ62 protective relay

SICAM PAS, the new substation control system by Siemens has been designed as an open system which employs IEC 61580 as communication standard between the bay and station control level. IEC 61580 supports interoperability and integration of substation control systems which facilitates system engineering independent of the manufacturer and reduces the planning expense at the same time. Direct operation of a SIPROTEC 4 relay All operator actions can be executed and information displayed on an integrated user interface.

6 Freely programmable function keys 7 Numerical keypad

Front view of the 7SJ63 relay combining protection, monitoring and control functions

C C

C

C

C

C

Large non-reflective back-lit display Programmable (freely assignable) LED's for important messages Arrows arrangement of the keys for easy navigation in the function tree Operator-friendly input of the setting values via the numeric keys or with a PC by using the D IGSI 4 software Command input protected by key lock (6MD63/7SJ63 only) or password Four programmable keys for frequently used functions “at the touch of a button”

Many advantages are already to be found on the clear and user-friendly front panel: C Ergonomic arrangement and grouping of the keys

8

DIGSI 4 – the operating software for all SIPROTEC relays For the user, DIGSI is synonymous with convenient, user-friendly parameterizing and operation of numerical protection relays. DIGSI 4 is a logical innovation for operation of protection and bay control units of the SIPROTEC 4 family. The PC software DIGSI 4 is the human-machine interface between the user and the SIPROTEC 4 units. It features modern, intuitive operating procedures. With DIGSI 4, the SIPROTEC 4 units can be configured and queried. C

C

C

C

C

C

The interface provides you only with what is really necessary, irrespective of which unit you are currently configuring. Contextual menus for every situation provide you with made-tomeasure functionality – searching through menu hierarchies is a thing of the past. Explorer operation on the MS Windows standard shows the options in logically structured form. Even with routing, you have the overall picture – a matrix shows you at a glance, for example, which LED's are linked to which protection control function(s). It just takes a click with the mouse to establish these links by a fingertip. Thus, you can also use the PC to link up with the relay via star coupler or channel switch, as well as via the PROFIBUS® of a substation control system. The integrated administrating system ensures clear addressing of the feeders and relays of a substation. Access authorization by means of passwords protects the individual functions, such as parameterizing, commissioning and control, from unauthorized access.

C

When configuring the operator environment and interfaces, we have attached importance to continuity with the SICAM automation system. This means that you can readily use DIGSI 4 on the station control level in conjunction with SICAM.

Display editor (Photo 8/10) A display editor is available to design the display of SIPROTEC 4 units. The predefined symbol sets can be expanded to suit the user. The drawing of a one-line diagram is extremely simple. Load monitoring values (analog values) can be set, i f required.

Configuration matrix (routing) The DIGSI 4 matrix allows the user to see the overall view of the relay configuration at a glance. For example, you can display all the LED's that are linked to binary inputs or show external signals that are connected to the relay. And with one mouse click, connections can be switched.

Commissioning Special attention has been paid to commissioning. All binary inputs and outputs can be read and set directly. This can simplify the wire checking process significantly for the user. CFC: graphic configuration With the help of the graphical CFC (Continuous Function Chart) Tool, you can configure interlocks and switching sequences simply by drawing the logic sequences; no special knowledge of software is required. Logical elements such as AND, OR and time elements are available. Hardware and software platform C

C

C

C

C

Pentium 1,6 GHz or better, with at least 128 Mbytes RAM DIGSI 4 requires more than 500 Mbytes hard disk space One free serial interface to the protection device (COM 1 or COM 4) One DVD/CD-ROM drive (required for installation) WINDOWS 2000, or XP Professional

Protection and Substation Control

Photo 8/9 

Photo 8/6 

DIGSI 4 Manager

Photo 8/7 

Functional scope

DIGSI 4 routing matrix

Photo 8/10  Display editor

Photo 8/8 

The device with all its parameters and process data

Photo 8/11

CFC logic with module library

8

Fault analysis The evaluation of faults is simplified by numerical protection technology. In the event of a fault in the power system, all events as well as the analog traces of the measured voltages and currents are recorded. The following types of memory have been integrated in the numerical protection relay: C 1 operational event memory. Alarms that are not directly assigned to a fault in the network (e.g. monitoring alarms, alternation of a set value, blocking of the automatic reclosure function). C 5 fault-event histories. Alarms that occurred during the last 3 faults on the network (e.g. type of fault detection, trip commands, fault location, auto-reclose commands). A reclose cycle with one or more reclosures is treated as one fault history. Each new fault in the network overrides the oldest fault history. C A memory for the fault recordings for voltage and current. Up to 8 fault recordings are stored. The fault recording memory is organized as a ring buffer, i.e. a new fault entry overrides the oldest fault record. C 1 ground-fault event memory (optional for isolated or impedance grounded networks). Event recording of the sensitive ground fault detector (e.g. faulty phase, real component of residual current).

The time tag attached to the fault records is the relative time of fault detection with a resolution of 1 ms. Devices with integrated battery backup clock store operational events and fault detection events with the internal clock time and a data stamp. The memory for operational events and fault record events is protected against failure of auxiliary supply with battery back-up supply. The integrated operator interface or a PC supported by the DIGSI 4 programming tool is used to retrieve fault reports as well as for the input of settings and routing. Evaluation of fault records Readout of the fault record by DIGSI 4 is done by fault-proof scanning procedures in accordance with the standard recommendations for transmission of fault records. A fault record can also be read out repeatedly. In addition to analog values, such as voltage and current, binary tracks can also be transferred and presented. DIGSI 4 is supplied together with the SIGRA® (DIGSI 4 Graphic) program, which provides the customer with full graphical operating and evaluation functionality like that of the digital fault recorders (oscillostores) by Siemens (see Photo 8/12).

Photo 8/12  Display and evaluation of a fault record using DIGSI 4 software

Real-time presentation of analog disturbance records, overlaying and zooming of curves and visualization of binary tracks (e.g. trip command, reclose command, etc.) are also part of the extensive graphical functionality, as are setting of measurement cursors, spectrum analysis and fault resistance derivation. Data security, data interfaces DIGSI 4 is a closed system as far as protection parameter security is concerned. The security of the stored data of the operating PC is ensured by checksums. This means that it is only possible to change data with DIGSI 4, which subsequently calculates a checksum for the changed data and stores it with the data. Changes in the data and thus in safety-related protection data are reliably recorded.

Protection and Substation Control

DIGSI 4 is, however, also an open system. The data export function supports export of parameterization and routing data in standard ASCII format. This permits simple access to these data by other programs, such as test programs, without endangering the security of data within the DIGSI 4 program system.

Office

Analog ISDN DIGSI PC, remotely located

With the import and export of fault records in IEEE standard format COMTRADE (ANSI), a high-performance data interface is produced which supports import and export of fault records into the DIGSI 4 partner program SIGRA.

Substation

This enables the export of fault records from Siemens protection units to customer-specific programs via the COMTRADE format.

RS232

Modem

Star coupler DIGSI PC, centrally located in the substation (option)

7XV53

Modem, optionally with call-back function

Signal converter RS232 RS485 bus

Remote relay interrogation

RS485

The numerical relay range of Siemens can also be operated from a remotely located PC via modem-telephone connection. Up to 254 relays can be addressed via one modem connection if the 7XV53 star coupler is used as a communication node (Fig. 8/14). The relays are connected to the star coupler via optical fiber links. Every protection device which belongs to a DIGSI 4 substation structure has a unique address.

7SJ60

Fig. 8/14

7RW60

7SD60

7**5

7**6

Remote relay communication

The relays are always listening, but only the addressed one answers the operator command which comes from the central PC. If the relay located in a station is to be operated from a remote office, then a device file is opened in DIGSI 4 and the protection dialog is chosen via modem.

This way, secure and time-saving remote setting and readout of data are possible. Remote diagnostics and control of test routines are also possible without the need of on-site checks of the substation.

After password input, DIGSI 4 establishes a connection to the protection device after receiving a call-back from the system.

8

Enclosures and terminal systems The protection devices and the corresponding supplementary devices are available mainly in 7XP20 housings. Installation of the modules in a c abinet without the enclosure is not permissible. The width of the housing conforms to the 19" system with the divisions 1/6, 1/3, 1/2 or 1/1 of a 19" rack. The termination module is located at the rear of devices for panel flush mounting or cabinet mounting. Screw terminals are available for devices intended for: C Panel and cabinet mounting and C Devices with a separate operator station The following screw-connection types are to be distinguished: C Connector modules for voltage connection and C Connector modules for current connection Clamping screws are slotted screws which shall be tightened with a screw driver. A simple, 6 x 1 slotted screw driver is suitable for this type of screw heads.

Ring tongue connectors and forked cable lugs can be used for connection. To meet the insulation path requirements, insulated cable lugs must be used. Or else, the crimping zone must be insulated by other suitable means (e.g. by covering it with shrinkdown plastic tubing). The following requirements must be observed: Cable lugs  Bolt diameter is 4 mm; maximum outer diameter is 10 mm; for cable cross sections of 1.0 mm to 2.6 mm AWG 16 to 14 accordingly. Only use copper conductors! Direct connection Solid conductors or litz conductors with end sleeves; for cable cross sections of 0.5 mm to 2.6 mm AWG 20 to 14 accordingly. The terminating end of the single strand or conductor must be pushed into the terminal compartment in such a way that it will be pulled into it when the clamping screw is tightened. Only use copper conductors! Wire stripping length 9 mm to 10 mm for solid conductors. Tightening torque  Max. 1.8 Nm. The heavy-duty current plug connectors provide automatic short-circuiting of the current transformer circuits when the modules are withdrawn. Whenever secondary circuits of current transformers are concerned,

special precautions are to be taken. In the housing version for surface mounting, the terminals are wired up on terminal strips on the top and bottom of the device. For this purpose two-tier terminal blocks are used to attain the required number of terminals. According to IEC 60529, the degree of protection is indicated by the identifying IP, followed by a number for the degree of protection. The first digit indicates the protection against accidental contact and ingress of solid foreign bodies, the second digit indicates the protection against water. 7XP20 housings are protected against ingress of dangerous parts, dust and dripping water (IP 51). For mounting of devices into switchgear cabinets, 8MC switchgear cabinets are recommended. The standard cabinet has the following dimensions: 2,200 mm x 900 mm x 600 mm (H x W x D). These cabinets are provided with a 44 U high mounting rack (standard height unit U = 44.45 mm). It can swivel as much as 180° in a swing frame. The rack provides for a mounting width of 19", allowing, for example, 2 devices with a width of 1/2 x 19" to be mounted. The devices in the 7XP20 housing are secured to rails by screws. Module racks are not required.

Protection and Substation Control

8.3 Relay Selection Guide

Type Protective functions

  n   o    i    t   c   e    t   o   r   p   e   c   n   a    t   s    i    D

   l   a    i    t   e  n   n   d  o   s   e    i   r   i   u  r   e   g  a    f   p    f    i   e    d  v   a  m   o   e   r   w  c    i    l   t   w  a   c  n   e    t   i    t   r   o    l   p  r    i   u    P   O  c

   t   n   e   r   r   u   c   r   e   v    O

   6    A    S    7

   0    0    6    D    S    7

   0    1    6    D    S    7

   5    4    J    S    7

   6    4    J    S    7

   0    0    6    J    S    7

   2    0    6    J    S    7

   1    6    J    S    7

   2    6    J    S    7

   3    6    J    S    7

   4    6    J    S    7

   0    6    H    V    7

   2    1    6    T    U    7

   3    1    6    T    U    7

   3    6    T    U    7

   0    6    S    S    7

      l     a       i       t      n     e     r     e       f       f       i       D

ANSI No.1)

Description

14

Locked rotor

–

–

–

–

–

–

–

V

V

V

V

–

–

–

–

–

21

Distance protection, phase

C

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

21N

Distance protection, ground

C

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

21FL

Fault locator

C

–

–

–

–

–

–

–

V

V

V

–

–

–

–

–

24

Overfluxing ( U/f)

–

–

–

–

–

–

–

–

–

–

–

–

V

V

–

–

25

Synchro-check

V

–

–

–

–

–

–

–

–

–

V

–

–

–

–

–

27

Undervoltage

V

–

–

–

–

–

–

–

V

V

V

–

–

–

–

–

27/34

U/f protection voltage/frequency protection

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

32

Directional power

–

–

–

–

–

–

–

–

–

–

V

–

–

–

–

–

32F

Forward power

–

–

–

–

–

–

–

–

–

–

V

–

–

–

–

–

32R

Reverse power

–

–

–

–

–

–

–

–

–

–

V

–

–

–

–

–

37

Undercurrent or underpower

–

–

–

–

–

–

V

C

C

C

C

–

–

–

–

–

40

Protection against under-excitation

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

46

Load unbalance protection

–

–

–

–

–

–

C

C

C

C

C

V

–

V

–

–

47

Phase sequence monitoring

C

–

–

–

–

–

–

–

C

C

C

–

–

–

–

–

48

Start-up current-time monitoring

–

–

–

–

–

–

V

V

V

V

V

–

–

–

–

–

49

Thermal overload

V

–

C

–

–

C

C

C

C

C

C

C

C

C

–

–

49R

Rotor overload protection

–

–

–

–

–

C

C

C

C

C

C

–

–

–

–

–

49S

Stator overload protection

–

–

–

–

–

C

C

C

C

C

C

–

–

–

–

–

50

Instantaneous overcurrent

C

C

C

C

C

C

C

C

C

C

C

–

C

C

C

–

50N

Instantaneous ground fault overcurrent

C

–

C

–

–

C

C

C

C

C

C

–

C

C

C

–

50BF

Breaker failure

V

–

V

–

–

–

C

C

C

C

C

V

V

V

V

–

51GN

Stator ground-fault overcurrent

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

51

Overcurrent with time delay

C

C

C

C

C

C

C

C

C

C

C

–

C

C

C

–

C

Standard function

1)

ANSI (American National Standards Institute) /IEEE (Institute of Electrical and Electronic Engineers) C 37.2: IEEE Standard Electrical Power System Device Function Numbers

Table 8/6 

V

Option

Relay selection guide

8

Type Protective functions

  n   o    i    t   c   e    t   o   r   p   e   c   n   a    t   s    i    D

   l   a    i    t   e  n   n   d  o   s   e    i   r   i   u  r   e   a   g    f    f   e  p    i   v    d  a  m   o   e   r   w  c    i    l   t   w  a   c  n   e    t   i    t   o   r   r    l    i   p  u    P   O  c

   t   n   e   r   r   u   c   r   e   v    O

   6    A    S    7

   0    0    6    D    S    7

   0    1    6    D    S    7

   5    4    J    S    7

      l     a       i       t      n     e     r     e       f       f       i       D

   6    4    J    S    7

   0    0    6    J    S    7

   2    0    6    J    S    7

   1    6    J    S    7

   2    6    J    S    7

   3    6    J    S    7

   4    6    J    S    7

   0    6    H    V    7

   2    1    6    T    U    7

   3    1    6    T    U    7

   3    6    T    U    7

   0    6    S    S    7

ANSI No.1)

Description

51N

Ground-fault overcurrent with time delay

C

–

C

C

C

C

C

C

C

C

C

–

C

C

C

–

51V

Voltage-dependent overcurrent-time protection

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

59

Overvoltage

V

–

–

–

–

–

–

–

V

V

V

–

–

–

–

–

59N

Residual voltage ground-fault protection

V

–

–

–

–

–

C

–

C

C

C

–

–

–

–

–

64

100% rotor ground fault protection (20 Hz)

–

–

–

–

–

–

–

–

–

–

–

–

–

–

––

64R

Rotor ground fault

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

67

Directional overcurrent

–

–

–

–

–

–

–

–

C

C

C

–

–

–

–

–

67N

Directional ground-fault overcurrent

V

–

–

–

–

–

C

–

C

C

C

–

–

–

–

–

67G

Stator ground fault, directional overcurrent

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

68

Oscillation detection (Block Z ,

51

t

I 2>,

51N

t

46

ARC

2)

8.4 Typical Protection Schemes

 I >,

C

t

I E>,

51

t

I 2>,

51N

7SJ60

79 1)

t 7SJ60

46

Radial systems Notes on Fig. 8/15  1) ANSI no. 79 only for reclosure with overhead lines. 2)Negative sequence o/c protection 46 as back-up protection against asymmetrical faults. General notes:  C The relay (D) with the largest distance from the infeed point has the shortest tripping time. Relays further upstream have to be timegraded against the next downstream relay in steps of about 0.3 seconds. C Dependent curves can be selected according to the following criteria: C Definite time: Source impedance is large compared to the line impedance, i.e. small current variation between near and far end faults C Inverse time: Longer lines, where the fault cur rent is much less at the end of the line than at the local end. C Highly or extremely inverse time: Lines where the line impedance is large compared to the source impedance (high difference for closein and remote faults) or lines, where coordination with fuses or reclosers is necessary. Steeper characteristics also provide higher stability on service restoration (probes for cold load pickup and transformer inrush currents).

Load I >,

D

t

I E>,

51

t

I 2>,

51N

t 7SJ60

46

* Alternatives: 7SJ45/46, 7SJ61 Load Fig. 8/15 

Load

Protection scheme with definite-time overcurrent-time protection

Infeed Transformer protection, see Fig. 8/22 52

52

7SJ60*

52

 I >,

t

51

7SJ60* I E>,

t

51N

I 2>,

46

t

52

ϑ> 49

 I >,

51

t

I E>,

t

51N

I 2>,

46

t

ϑ> 49

* Alternatives: 7SJ45/46, 7SJ61

Fig. 8/16 

Protection scheme for ring circuit

Ring circuits General notes on Fig. 8/16  C

Tripping times of overcurrent relays must be coordinated with downstream fuses of load transformers. (Highly inverse time characteristic

C

C

with about 0.2 s grading-time delay to be preferred) Thermal overload protection for the cables (option) Negative sequence o/c protection 46 as sensitive protection against unsymmetrical faults (option)

8

Infeed

52

 I >>,  I >,

 I E>>,

 I 2>,

50N/ 51N

46

 I E>,

50/ 51

Distribution feeder with reclosers General notes on Fig. 8/17:  C The feeder relay operating characteristics, delay times and autoreclosure cycles must be carefully coordinated with downstream reclosers, switch disconnectors and fuses. The instantaneous zone 50/50N is normally set to reach out to the first main feeder sectionalizing point. It has to ensure fast clearing of closein faults and prevent blowing of fuses in this area (“fuse saving”). Fast autoreclosure is initiated in this case. Further time-delayed tripping and reclosure steps (normally 2 or 3) have to be graded against the recloser. C The o/c relay should automatically switch over to less sensitive characteristics after longer load interruption times to enable overriding of subsequent cold load pickup and transformer inrush currents.

t

t

52

t 7SJ60 7SJ61

79

Autoreclose

Further feeders

Recloser

Sectionalizers

Fuses

Fig. 8/17

Protection scheme for distribution feeder 

Infeed 52 52

 I >,

t

I E>,

51

51N

t

ϑ>

I 2>,

49

46

52

t 7SJ60

OH line or cable 2

OH line or cable 1

67

67N

51

51N

Protection same as line or cable 1

7SJ62

52 52 52

Fig. 8/18 

52

52

Load

Load

Protection concept for parallel lines

Parallel lines General notes on Fig. 8/18:  C This configuration is preferably used for the uninterrupted supply of important consumers without significant backfeed. C The directional o/c protection 67/67N trips instantaneously for

C

faults on the protected line. This allows the saving of one timegrading interval for the o/c relays at the infeed. The o/c relay functions 51/51N have each to be time-graded against the relays located upstream.

Protection and Substation Control Infeed 52 52 52

7SJ60

1)

79

52 2)

51N/ 51N

Cables or short overhead lines with infeed from both ends

Line or cable

2) Overload protection only with cables 3) Differential protection options: C Type 7SD610 with direct fiber-optic connection up to about 35 km (approx. 22 miles) or via a 64 kbit/s channel of a general purpose PCM connection (optical waveguide, microwave) C Type 7SD600 with 2-wire pilot cables up to about 12 km (approx. 7.5 miles)

7SJ60

7SD600 or 7SD610

4)

7SD600 or 7SD610

4)

Same protection for parallel line, if applicable

3)

51N/ 51N

Notes on Fig. 8/19:  1) Auto-reclosure only with overhead lines

49

87L

49

87L

2) 79

52

52

1)

52 52 Load Fig. 8/19 

52

52

52

Backfeed Protection scheme using differential protection

HV infeed 52

4) Functions 49 and 79 only with relays of type 7SD610. 7SD600 is a cost-effective solution where only the function 87L is required (external 4AM4930 current summation transformer to be installed separately).

63

 I >>

I >,

50

51

R N

t

I E>

ϑ>

 I 2>,

50N

49

46

t 7SJ60

Optional resistor or reactor

 I >>

87N 51G 52

7VH60

7SJ60

IE> Distribution bus

52 o/c relay Load Fig. 8/20 

Fuse Load

Protection scheme for small transformers

Small transformer infeed General notes on Fig. 8/20:  C Ground faults on the secondary side are detected by current relay 51G which, however, has to be time-graded against downstream feeder protection relays. The restricted ground-fault relay 87N may additionally be used to achieve fast clearance of earth faults in the secondary transformer winding. Relay

7VH80 is of the high-impedance type and requires class X current transformers with similar transformation ratio. C

Primary breaker and relay may be replaced by fuses.

8

Dual infeed with single transformer Notes on Fig. 8/21:  1) Line current transformers are to be connected to isolate stabilizing inputs of the differential relay 87T in order to assure stability in case of line-through-fault currents.

Protection line 1 same as line 2

Protection line 2 21/21N or 87L + 51 + optionally 67/67N

52

52 7SJ60 oder 7SJ61  I >>

I >,

50

2) Relay 7UT613 provides numerical ratio and vector group adaptation. Matching transformers, as used with traditional relays, are therefore no longer necessary.

63

Parallel incoming to transformer feeders

t

I E>,

51

51N

46

49

 I 2>

ϑ> 87N

7SJ60

Note on Fig. 8/22:  The directional functions 67 and 67N do not apply for cases where the transformers are equipped with transformer differential relays 87T.

t

 I >>

I E>

51

51N

87T

7UT613

51G

7SJ60

52 52

52

Load bus

52

Load Transformer protection scheme

Fig. 8/21

HV infeed 1 52

 I >>

50

I >,

t

 I E>,

t

51N

ϑ>

I 2>,

49

46

52

t

Protection same as infeed 1

7SJ62

 I >,

t

I E>,

51

63

51G

HV infeed 2

7SJ60 or 7SJ61

t

51

I E>,

 I >

t 67

51N

I E>

67N

7SJ60

1) 52

52 Load bus 52

52 Load

Fig. 8/22 

52 Load

Protection scheme for transformers connected in parallel

Load

Protection and Substation Control

Small and medium-sized motors < 1 MW

52

With effective or low-resistance grounded infeed ( I E ≥ I N Motor) General note on Fig. 8/23:  Applicable to low-voltage motors and high-voltage motors with low-resistance grounded infeed (IE ≥ IN Motor).

 I E>

ϑ>

50

51N

49

 I 2>

Locked rotor 49 CR

7SJ60

46

M Protection scheme for small motors

Fig. 8/23 

With high-resistance grounded infeed ( I E ≤ I N Motor)

52

Notes on Fig. 8/24: 1)  1) Window-type zero-sequence current transformer. 2) Sensitive directional earth-fault protection 67N only applicable with infeed from isolated or Peterson-coil-grounded network. (For dimensioning of the sensitive directional ground-fault protection, also see application circuit No. 24)

 I >>

 I >>

ϑ>

I 2>

50

49

46

 I E>

7XR96 1) 60/1A

51G

 I <

7SJ62 or 7SJ602

37

3)

2) 67N

M Protection scheme for medium-sized motors

Fig. 8/24

3) Relay type 7SJ602 may be used for power systems with isolated neutral or compensated neutral 52

 I >>

ϑ>

U <  I 2>

Large HV motors > 1 MW Notes on Fig. 8/25:  1) Window-type zero-sequence current transformer.

50

3) This function is only needed for motors where the start-up time is longer than the safe stall time t E. According to IEC 79-7, t E is the time needed to heat up AC windings, when carrying the starting current  I A, from the temperature reached in rated service and at maximum ambient temperature to the limiting temperature.

 I E>

7XR96 1) 60/1A

2) Sensitive directional ground-fault protection 67N only applicable with infeed from isolated or Peterson-coil-grounded network.

49

51N

46  I <

2)

27 optionally

37

67N

Monitoring of the start-up 49T stage 3) 5)

87M

7UM62

3) Speed switch

Fig. 8/25 

M

Option: thermistor

4)

Protection scheme for large motors

8

A separate speed switch is used to monitor actual starting of the motor. The motor breaker is tripped if the motor does not reach speed in the preset time. The speed switch is part of the motor delivery itself.

MS

G

 I >,  I E>,

t

51 51N

4) Pt100, Ni100, Ni120

 I 2>

ϑ>

46

49

7SJ60

5) 49T can only be implemented using 7XV5662 thermobox Smallest generators < 500 kW

Fig 8/26 

Note on Fig. 8/26 and 8/27:  If a window-type zero-sequence current transformer is provided for sensitive ground-fault protection, relay 7SJ602 with separate ground current input can be used (similar to Fig. 8/24).

Protection scheme for smallest generators with solidly grounded neutral conductor

MS

G1

Generator 2

 I >,  I E>,

t

51 51N

1)

I 2>

ϑ>

46

49

7SJ60

Small generator up to 1 MW Note on Fig. 8/28:  Two current transformers in V-connection are sufficient.

R N

Fig. 8/27 

=

V N

√3 • (0.5 to 1) •  I rated

Protection scheme for smallest generators with a resistance-grounded neutral conductor

52

1)

Field

G

f > <

81

 I >,

t

51  I E>,

ϑ>

 I 2>

49

46

t

51N

Fig. 8/28 

Protection scheme for generators > 1 MW

P >

32

U >

59

7UM61

Protection and Substation Control

Generators > 1 MW Notes on Fig. 8/29:  1) Functions 81 and 59 only required where drives can assume excess speed and voltage controller may permit rise of output voltage above upper threshold.

MS 52

50 27

2) The integrated differential protection function may be used as longitudinal or transverse differential protection for the generator.

   I >/ U<

1)

59

U <

2)

∆ I  1)

R E field<

G

f > <

7UM62

64R Field  I 2>

ϑ>

46

49  I E>,

 I >t, U <

51V

40

-P >

L.O.F. 32

t

51N

Fig. 8/29 

81

87

87N

Protection scheme for generators > 1 MW

8

Busbar protection by o/c relays with reverse interlocking

Infeed

General note on Fig. 8/30:  Applicable to busbars without substantial (< 0,25 x  I N) backfeed from the outgoing feeders.

Reverse interlocking

7SS60 busbar protection

 I >, t0

I >,

50 50N

General note on Fig. 8/31 C Applicable for single and double busbars C Different current transformer ratios are balanced by intermediate-circuit transformers C Unrestricted number of feeders C Feeder protection may be connected to the same current transformer core

t

51 51N

7SJ60

52

t0 = 50 ms

52

 I >

50 50N

I >,

t

52

51 51N

I >

I >,

50 50N

51 51N

7SJ60

Fig. 8/30 

t

52

 I >

I >,

50 50N

51 51N

7SJ60

7SJ60

Busbar protection with reverse interlocking

7MT70

7SS601

87 BB 52 86 52

52

52

7SV60

7SV60

7SV60

50 BF

50 BF

50 BF

Load

Fig. 8/31

S 7SS60 busbar protection

G

t

1)

7SS60

Protection and Substation Control

8