Category: ABB

HSR applies the PRP principle of parallel operation to a single

ring. For each message sent, the node sends two frames, one

through each port. Both frames circulate in opposite directions

over the ring. Every node forwards the frames it receives from

one port to another to reach the next node. When the

originating sender node receives the frame it sent, the sender

node discards the frame to avoid loops. The HSR ring supports

the connection of up to 30 relays. If more than 30 relays are to

be connected, it is recommended to split the network into

several rings to guarantee the performance for real-time

applications.

The relay can be connected to Ethernet-based communication

systems in a station bus using the RJ-45 connector (100Base

TX) or the multimode fiber optic LC connector (100Base-FX). A

dedicated protection communication port uses a pluggable

multimode or single-mode fiber optic LC connector (100Base

FX). If connection to a serial bus is required, the RS-485 or

fiber-optic serial communication ports can be used.

Modbus implementation supports RTU, ASCII and TCP modes.

Besides standard Modbus functionality, the relay supports

retrieval of time-stamped events, changing the active setting

group and uploading of the latest fault records. If a Modbus

TCP connection is used, five clients can be connected to the

relay simultaneously. Further, Modbus serial and Modbus TCP

can be used in parallel, and, if required, both IEC 61850 and

Modbus can be run simultaneously.

Modbus and DNP3 protocols.

The IEC 61850 standard specifies network redundancy which

improves the system availability for the substation

communication. The network redundancy is based on two

complementary protocols defined in the IEC 62439-3 standard:

PRP and HSR protocols. Both protocols are able to overcome a

failure of a link or switch with a zero switchover time. In both

protocols, each network node has two identical Ethernet ports

dedicated for one network connection.

The protocols rely on the duplication of all transmitted

information and provide a zero switchover time if the links or

switches fail, thus fulfilling all the stringent real-time

requirements of substation automation.

In PRP, each network node is attached to two independent

networks operated in parallel. The networks are completely

separated to ensure failure independence and can have

different topologies. As the networks operate in parallel, they

provide zero-time recovery and continuous checking of

redundancy to avoid failures.

The relay also supports IEC 61850 process bus concept by

sending and receiving sampled values of currents and voltages.

With this functionality the galvanic interpanel wiring can be

replaced with Ethernet communication. The analog values are

transferred as sampled values using the IEC 61850-9-2 LE

protocol. REX640 supports publishing of one and subscribing

of four sampled value streams. The intended application for

sampled values are current-based differential protection

functions or sharing the voltage values with the relays that have

voltage-based protection or supervision functions. The relay

can receive up to four sampled value streams and totally 16

measurements can be connected into the protection relay

application.

Relays with process bus based applications use IEEE 1588

edition 2 for high-accuracy time synchronization.

For redundant Ethernet communication in station bus, the relay

offers either two optical or two galvanic Ethernet network

interfaces. An optional third port with optical or galvanic

Ethernet network interface is also available. The relay also

provides an optional fiber-optic port for dedicated protection

communication which can be used for up to 50 km distances

depending on the selected fiber transceiver. The intended

teleprotection applications for this port are line differential and

line distance protection communication or binary signal

transfer. The optional third Ethernet interface provides

connectivity for any other Ethernet device to an IEC 61850

station bus inside a switchgear bay, for example connection of

a remote I/O. Ethernet network redundancy can be achieved

using the high-availability seamless redundancy (HSR) protocol

or the parallel redundancy protocol (PRP), or with a self-healing

ring using RSTP in the managed switches. Ethernet

redundancy can be applied to the Ethernet-based IEC 61850.

Station communication

Operational information and controls are available through a

wide range of communication protocols including IEC 61850

Edition 2. IEC 61850-9-2 LE, IEC 60870-5-103. IEC

60870-5-104. Modbus® and DNP3. The Profibus DPV1

communication protocol is supported via the protocol

converter SPA-ZC 302. Full communication capabilities, for

example, horizontal communication between the relays, are

only enabled by IEC 61850.

The IEC 61850 protocol is a core part of the relay as the

protection and control application is fully based on standard

modelling. The relay supports Edition 2 and Edition 1 versions

of the standard. With Edition 2 support, the relay has the latest

functionality modelling for substation applications and the best

interoperability for modern substations. The relay supports

flexible product naming (FPN) facilitating the mapping of relay’s

IEC 61850 data model to a customer defined IEC 61850 data

model.

The IEC 61850 communication implementation supports

monitoring and control functions. Additionally, parameter

settings, disturbance recordings and fault records can be

accessed using the IEC 61850 protocol. Disturbance

recordings are available to any Ethernet-based application in

the standard COMTRADE file format. The relay supports

simultaneous event reporting to five different clients on the

station bus.

The relay can send binary and analog signals to other devices

using the IEC 61850-8-1 GOOSE (Generic Object Oriented

Substation Event) profile. Binary GOOSE messaging can, for

example, be used for protection and interlocking-based

protection schemes. The relay meets the GOOSE performance

requirements for tripping applications in distribution

substations, as defined by the IEC 61850 standard (class P1.

<3 ms data exchange between the devices). The relay also

supports the sending and receiving of analog values using

GOOSE messaging. Analog GOOSE messaging enables easy

transfer of analog measurement values over the station bus,

thus facilitating, for example, the sending of measurement

values between the relays when controlling transformers

running in parallel.

Access control and cybersecurity

Cybersecurity measures are implemented to secure safe

operation of the protection and control functions. The relay

supports these measures with configuration hardening

capabilities, encrypted communication, Ethernet filter and rate

limiter, security event logging and user access control.

The relay supports role-based user authentication and

authorization with individual user accounts as defined in IEC

62351-8. All user activity is logged as security events to an

audit trail in a nonvolatile memory and sent as messages to the

SysLog server. The nonvolatile memory does not need battery

backup or regular component exchange to maintain the

memory storage. File transfer and Web HMI use communication

encryption protecting the data in transit.

Also, the communication link between the relay configuration tool

PCM600 and the relay is encrypted. All rear communication

ports and optional protocol services can be activated according

to the required system setup.

User accounts can be managed by PCM600 or centrally. A

central account management is an authentication infrastructure

that offers a secure solution for enforcing access control to

relays and other systems within a substation. This incorporates

management of user accounts, roles and certificates and the

distribution of such, a procedure completely transparent to the

user. The central server handling user accounts can be, for

example, SDM600 or an Active Directory (AD) server such as

Windows AD.

The relay supports full Public Key Infrastructure as defined by

IEC 62351-9. With this, the user can ensure that the certificates

used in secured communication are from a user-approved

provider instead of device self-signed certificates.

Load profile

The load profile recorder stores the historical load data

captured periodically (demand interval). Up to 12 load

quantities can be selected for recording and storing in the

nonvolatile memory. The recordable quantities include

currents, voltages, power and power factor values. The

recording time depends on a settable demand interval

parameter and the amount of quantities selected. The

quantities’ type and amount to be recorded are determined in

the application configuration. The recorded quantities are

stored in the COMTRADE format.

Trip circuit supervision

The trip circuit supervision continuously monitors the availability

and operability of the trip circuit. It provides open-circuit

monitoring both when the circuit breaker is in closed and in

open position. It also detects loss of circuit-breaker control voltage.

Self-supervision

The relay’s built-in self-supervision system continuously

monitors the state of the relay hardware and the operation of

the relay software. Any fault or malfunction detected is used for

alerting the operator.

A permanent relay fault blocks the protection functions to

prevent incorrect operation.

Event log

To collect sequence-of-events information, the relay has a

nonvolatile memory capable of storing 1024 events with the

associated time stamps. The event log facilitates detailed pre

and post-fault analyses of feeder faults and disturbances. The

considerable capacity to process and store data and events in

the relay supports the growing information demand of future

network configurations.

The sequence-of-events information can be accessed either via

the LHMI or remotely via the communication interface of the

relay. The information can also be accessed locally or remotely

using the Web HMI.

Recorded data

The relay can store the records of the latest 128 fault events.

The records can be used to analyze the power system events.

Each record includes, for example, current, voltage and angle

values and a time stamp. The fault recording can be triggered

by the start or the trip signal of a protection block, or by both.

The available measurement modes include DFT, RMS and

peak-to-peak. Fault records store relay measurement values

when any protection function starts. In addition, the maximum

demand current with time stamp is separately recorded. The

records are stored in the nonvolatile memory.

Disturbance recorder

The relay is provided with a disturbance recorder featuring up to

24 analog and 64 binary signal channels. The analog channels

can be set to record either the waveform or the trend of the

currents and voltages measured.

The analog channels can be set to trigger the recording function

when the measured value falls below or exceeds the set values.

The binary signal channels can be set to start a recording either

on the rising or the falling edge of the binary signal or on both.

The binary channels can be set to record external or internal

relay signals, for example, the start or trip signals of the relay

stages, or external blocking or control signals. The recorded

information is stored in a nonvolatile memory in COMTRADE

format and can be uploaded for subsequent fault analysis.

Fault locator

The relay features an optional impedance-measuring fault

location function suitable for locating short circuits in radial

distribution systems. Earth faults can be located in effectively

and low-resistance earthed networks, as well as in

compensated networks. When the fault current magnitude is at

least of the same order of magnitude or higher than the load

current, earth faults can also be located in isolated neutral

distribution networks. The fault location function identifies the

type of the fault and then calculates the distance to the fault

point. The calculations provide information on the fault

resistance value and accuracy of the estimated distance to the

fault point.

The voltage unbalance and voltage variation functions are used

for measuring short-duration voltage variations and monitoring

voltage unbalance conditions in power transmission and

distribution networks.

The voltage and current harmonics functions provide a method

for monitoring the power quality by means of the current

waveform distortion and voltage waveform distortion. The

functions provide selectable short-term 3- or 60- or 300

second sliding average and a long-term demand for total

demand distortion (TDD) and total harmonic distortion (THD).

The phase-specific harmonic content is measured for voltages

and currents, as well as DC component and fundamental

content. The dedicated harmonics measurement page in the

LHMI presents the measurements in a user-friendly manner.

Fault locator

The relay features an optional impedance-measuring fault

location function suitable for locating short circuits in radial

distribution systems. Earth faults can be located in effectively

and low-resistance earthed networks, as well as in

compensated networks. When the fault current magnitude is at

least of the same order of magnitude or higher than the load

current, earth faults can also be located in isolated neutral

distribution networks. The fault location function identifies the

type of the fault and then calculates the distance to the fault

point. The calculations provide information on the fault

resistance value and accuracy of the estimated distance to the

fault point.

Power quality

In the EN standards, power quality is defined through the

characteristics of the supply voltage. Transients, short-duration

and long-duration voltage variations and unbalance and

waveform distortions are the key characteristics describing

power quality. The distortion monitoring functions are used for

monitoring the current total demand distortion and the voltage

total harmonic distortion.

Power quality monitoring is an essential service that utilities can

provide for their industrial and key customers. A monitoring

system can provide information about system disturbances and

their possible causes. It can also detect problem conditions

throughout the system before they cause customer complaints,

equipment malfunctions and even equipment damage or

failure. Power quality problems are not limited to the utility side

of the system. In fact, the majority of power quality problems

are localized within customer facilities. Thus, power quality

monitoring is not only an effective customer service strategy but

also a way to protect a utility’s reputation for quality power and

service.

The protection relay has the following power quality monitoring

functions.

• Voltage variation

• Voltage unbalance

• Current harmonics

• Voltage harmonics