substation automation

Unit 06 - Substation Automation - 1 -

Unit 06 - Substation Automation

Twenty years ago, the first local automatism appeared in electrical substations. Some of those

automatisms were used to eliminate earth faults by opening and closing cyclically the feeders in

HV/MV substations, others were in charge to permute automatically the transformers in EHV/HV

substations. These automatisms were so slow that both the operating staff and the customers

could follow these protection and optimisation procedures.

Today, the information technology (IT) has progressed in such a way that wide area protection

schemes can be realized that are in the position to protect the entire power system relying on

co-ordinated defence plans. They are the ultimate barriers intended to prevent the spreading of

losses of synchronism throughout the power system. Distributed computers, satellite based time

synchronization and communication, broadband communication networks and intelligent

substation automation systems and phasor measurement units (PMU) are involved in such

protection schemes. As the response of operating staff is too slow with the legacy technology in

emergency situations, the emergency control goes through all the automated control systems to

operate globally in less than 0.5 second.

In the meantime, electromechanical static, electronic and fully digital technology have been

successively installed in substations. The average outage time for an end customer went down

from 2 days to 10 minutes per year. Utilities are now selling quality of the electricity rather than

power of the electricity.

1. Necessary conditions to install new technology in substations

Four different aspects have to be considered in connection with the implementation of new

technologies in substations. These involve the electrical network, the utilities social aspect, the

end customer aspect and the utilities policy aspect. All have to be analysed in detail.

Electrical network consideration

Digital substation automation systems improve the control of the network. All basic functions like

telecontrol, local control, event recorder, disturbance recorder, numerical protection, automation

of substation automation (SA) systems are interacting with the entire power system control:


- The tele-control functionality allows the SCADA operating people to have a good

overview control on the network. They receive supervision information and can operate

the switchgear with the highest reliability.

- The control functions allow the operating people to run the substation as if they were

inside it. User-friendly human machine interfaces (HMI) provide the right information at

the right time. Easy to operate and to understand are the qualities of the control interface.

- The sequence of event recorders with time tagging at one millisecond, which are

incorporated in the intelligent electronic devices (IED)s for protection and control provide

comprehensive and precise information and can help protection people to improve the

global protection scheme (all SA have the same time reference).

- The disturbance recorders that are included in SA allow the network maintenance

engineers to analyse a faulty part of the network.

- Numerical protection relays improve the quality of the protection. This equipment can be

set with very good precision and their behaviour can even be dynamically adapted to

changing condition and topology.

- Automation is a very important point. This allows the SA to have self-response to

problems and to arrange in a predetermined configuration procedure the topology of the

network in few seconds. This cannot be equalled by the best SCADA operating people.

Commencing the installation of digital substation control systems requires very few conditions on

the electrical network. Existing SCADA can be used because SA can be adapted to their

communication protocol. Static or electromechanical relays can still be used even if the SA

implies digital relays for new installations. Existing substations can be enhanced stepwise. SA

systems can easily be connected and coordinated with switchgear placed on the lines and

cables.

Utility social aspect

Substation automation leads to unmanned substations and thus fewer operating people. This is

a fact and may mean a taboo aspect and an obstacle to introduce substation automation

systems. On the other hand, it can be a very important advantage in cases when the substations

are located far from the operation point. With a good training and good documentation, average

operating people have no problem to operate correctly a digital substation automation system,

locally or from remote.


With the integrated self-diagnostic facility in connection with a centralized maintenance centre,

just a few maintenance people are necessary. Substation automation makes preventive

maintenance obsolete and allows changing to "just in time maintenance" practices with the aid of

condition monitoring facilities.

In addition, substation automation means reduced time to design, erect and test substations.

Project teams can be reduced in number because of the fact that substation automation systems

are simpler to design, install and test. This means, however, that the introduction of SA must be

carefully prepared by the utility. Although the social consequences are important, the benefits for

the utility have to be given priority. There are less people involved but those need higher

qualification and their jobs are more challenging.

End customer aspect

Substation automation systems improve the quality of service and thus have a positive impact

on the reliability the power supply to the end customer. SA decreases the number of human

errors as SCADA people are enabled by means of digital interlocking schemes to control the

complex topology of the power network with higher reliability. Such guide control decreases the

number of operating faults, especially in emergency situations. Precise analyses of fault

conditions are processed by the SA. The disturbance recorder incorporated allows detecting

weak spots in the network that the interruptions of power for the end customer are minimized.

Automated functions allow the SA to control the levels of voltage, frequency and network

stability. The time that is necessary to initiate counter measures is around 200 milliseconds. This

number has to be compared with 5 seconds that is needed by the SCADA people to respond to

disturbances. Self-diagnostic included in the SA allows the maintenance people to repair very

quickly the faulty equipment

Utility business policy

The technical policy is involved because of changing to SA utilities can lose the control on what

will be installed in their substations. Typical problems occur when utilities buy different SA

systems under a price consideration only. The cheapest solutions change with the years. Five

years later, the utility has seven different suppliers, with seven or more different systems, a lot of

spare parts, and big difficulties to manage correctly the difficult situation, when small companies

do no longer exist. The introduction of SA also means optimisation of the substation and

reducing the global lifetime cost of the substation. Operating and maintenance policies have to


be reviewed to exploit the full benefits of SA as well as operating procedures, maintenance

periods and repair actions. The financial policy has to be changed, as the introduction of new

technologies requires consideration of the costs for the total life cycle of the equipment.

2. Advantages and drawbacks of new technologies

Social aspects

The new technologies may reduce the number of people necessary for SA design, erection, test,

operation and maintenance, but they also free people to take care for other important business

aspects like quality of services, optimisation of the network performance, improvement

customers interfaces and power system planning.

Financial aspects

The new technologies enable utilities to earn more money. The global lifetime costs of the

computerized substations are lower than conventional. The reliability is greater and the power

interrupts are shorter. But, the implementation of new technologies requires investments not only

because of the financial benefits but also due the fact that the knowledge for maintaining and

spares for repairing conventional relays is less and less available. Utilities need to rebuild or

rethink their sociaI policy, as well as operating and maintenance policies.

Network and energy management aspects

The new technologies allow a better optimisation of the network by using Energy Management

Systems (EMS) linked with digital substation control systems. Typical examples are:

- The integrated substation control systems receive a command from the operator for load

shedding and can execute this operation very quickly to safeguard the network stability.

- In emergency situations, voltage or frequency-monitoring devices can initiate load

shedding automatically to counteract wide area disturbances that may be caused by

cascaded tripping.

- As all substation control systems have the same time reference, it is possible to analyse

globally the response of the protection schemes of the network and in case of a fault to

analyse precisely why, where and when this fault has occurred.


End customers aspects

The new technologies improve the quality of service and power quality, reduce outage times and

increase the satisfaction of final customers.

3. Basics rules to preserve independence and to succeed

One of the most basic rules for all utilities that intend to introduce the SA technology is to stay

independent from vendors and to stay in a position that they have the choice of the equipment. A very important issue that assures independence is the strict rule to accept only systems that are

designed in accordance with International Standards, preferably with IEC 61850. This is of

particular importance for the communication within the substations. IEC 61850 is the only

standard that provides an open architecture and assures interoperability with IEDs from various

vendors, who offer compliancy with IEC 61850 implemented.

In the process of introducing the new technologies, it is highly recommend that utilities start with

feasibility studies to elaborate requirement specifications that correspond to their specific needs.

For the sake of independence, it is recommended to select two competent suppliers only and to

ask each of them to produce pilot installations including the complete functional and technical

specifications. The operating people should have their specific man-machine interface and the

maintenance engineers should obtain the documentation in accordance with their specific

documentation style guide. After the pilot installation is available comprehensive factory

acceptance tests should be conducted using a primary equipment simulator for product

approval. Such a product approval procedure should be applied only once to assure that the

right and feasible product is received on site.

To evaluate all these advantages or disadvantages is a very complex task and it is suggested to

define a single non-performance factor called ".Non Distributed Energy" (NDE) to analyse the

shortcomings in service. This NDE is a new unit, in the local currency by kWh, which represents

the difference of money between the two states of power system:

- The utility is able to deliver the energy to the end customer and

- The utility is not able to deliver

The valuation of the NDE is a very sensitive action because the NDE is not only the benefit by

delivered energy but includes all the activities of the utility. The NDE does not indicate where to

invest but indicates when and how much to invest. But non-quality of service translated in NDE


alone is a poor approach, if we do not consider other parameters as well. Level of voltage,

frequency, reactive power transfer, number of long and short time interrupts are important

parameters. One part of these parameters is involved in network stability.

Therefore utilities use as a more complete approach quality parameters, which are often the time

of interrupts coming from the electrical network and stations failures (F-Time) and time of

interrupts coming from works on the network and the substation (W-Time). Historical and

detailed information of these two parameters is very important so as to be able to determine

where to invest to increase the quality of service.

4. Management and utilization of substation data

Dedicated hardware devices for process data recording that were previously provided for data

retrieval from the control centre now become functional modules that are integrated into the

IEDs (Intelligent Electronic Devices). The RTU merely acts as a gateway to provide access to

these data, which are transmitted to the relevant historical database for storage and processing.

These data comprise:

- Sequence of event recordings

- Disturbance recordings

- Quality of supply measurands

- Statistical metering for power system planning purposes

- Accounting information

With these new features an SA system can be provided by the most cost effective functions like:

- System-wide under-frequency load shedding:

Dedicated IEDs monitor the system voltages, currents, frequency and power and are

communicating peer-to-peer on a real time basis over the corporate wide area network

(WAN). In case of power generation deficit detected they determine the most suitable

location for performing load shedding on the basis of real time voltage instability studies,

power swing predictions and actually measured loads.

- Redundant protection and control functions: The introduction of serial communication at process level allows IEDs to share analogue

and digital data on a real time basis and to perform mutual back-up functions. An IED


acting primarily as protection device may incorporate also back-up control functions that

are used, if the associated IED for control is faulty. The associated IED for control may

have a back-up protection functionality that can be activated automatically, if the

protection I ED has failed to operate.

- Intelligent power system voltage control: The active and reactive power flow in the network can be tracked system wide by means

of a dedicated voltage control function. As it knows the position of all transformer tap-

changers it can automatically adjust them from remote, and it also can switch capacitor

banks, or initiate of load shedding etc.

System Performance Aspects

In order to assure that the SA system performs adequately to conventional systems, the

following performance related aspects have to be addressed:

- Security, reliability, dependability and speed in order to ensure that the protection

functionality is not degraded and has highest priority at all times

- Flexibility, expandability and forward compatibility with newer systems to ensure that

future expansion can be accommodated at minimum costs

- Backward compatibility to allow integration with existing systems

A secure control hierarchy and corresponding interlocking has to ensure that remote control from

the SCADA as well as local control from the substation HMI is safe by verifying the validity of

control actions before execution. Redundancy of equipment and/or functionality has to ensure

that a single hardware failure does not expose neither the power system nor primary equipment

to unsafe and undesirable operating conditions.

5. Justification for substation automation

Most utilities today have identified potential benefits available from the implementation of

automation to their operations. These benefits generally fall into two distinct categories:

strategic and tangible. The strategic benefits result from programs designed to improve the

customer’s perception of quality, reliability and added value. Tangible benefits are derived from

programs to increase the ability of the organization to work better, faster, and cheaper. Table 1

includes examples of benefits falling under these categories.


Table 1: Examples of strategic and tangible benefit

Strategic benefits Tangible benefits

Improved quality of service Reduced manpower requirements

Improved reliability Reduced system implementation costs

Maintenance/expansion of customer base Reduced operating costs

High value service provider Reduced maintenance costs

Added value service Ability to defer capacity addition projects

Improved customer access to information Improved information for engineering decisions

Enterprise information accessibility Improved information for planning decisions

Flexible Billing Options Reduced customer outage time

Perception of Substation Automation

Until recently, automation in the substation has meant the presence of a SCADA remote terminal

unit (RTU) to many utility engineers. Substation automation is defined as a microprocessor

based system that integrates and processes substation status, analogue and control information

and communicates with local and/or remote devices. Actual, the capabilities of equipment that

qualify under this definition are quite varied. SA systems range from simple RTUs to fully

networked systems that manage WAN/LAN input/outputs and provide advanced services for the

substation environment and mainstream distribution automation functions.

Substation legacy systems and practices

Transmission substations have received the lion's share of automation devices in the past

because of the importance of their reliability to system operations. Automation devices at these

sites include RTUs, fault recorders, sequence of events recorders (SERs), annunciating panels,

and a few microprocessor based relays. Input/output to these devices was typically via

hardwired connections to instrument transformers, field and local status contacts, relays, and

control panels. The dominant protective devices were electromechanical relays. The local

operator interface was generally a control panel, analogue meters, annunciating window boxes,

and recording devices of various types.


Communication links, other than telephone connections, are typically between transmission sub-

and master stations via power, fiber optic, or dedicated telephone lines using relatively slow data

transfer rates from 1200 to 9600 baud. Most distribution substations today have a limited

number of IEDs. Many have RTUs, but few have been provided with automated fault recording

and microprocessor based relay systems.

Maintenance practices at legacy substations involve labour intensive routine on-site manual

inspection. Field devices such as circuit breakers, switchgear, transformers and load tap

changers are maintained routinely without detailed information on operation of these devices.

Many opportunities exist today to design, operate and maintain substations using better, faster

and cheaper devices and service methodologies. These efficiencies are accomplished by

eliminating unnecessary redundant systems and using microprocessor based controllers to

manage information supplied by IEDs.

Typically, substation automation passes justification tests under the following conditions.

- New construction:

substitution of RTUs, mimic style control panels, annunciaters, sequence of events

recorders (SERs), fault recorders, cable/conduit systems, and significant control room

space

- Significant retrofit or expansion of existing substation:

capital projects add new bays, transformers or switchgear can easily incorporate SA

retrofit projects

- Upgrading the WAN to high speed capabilities such as Ethernet speeds:

RTU architectures normally communicating with SCADA master stations at 1200 baud

will not be compatible with the high speed data transfer and synchronizing required by

modern WANs.

- New or replacement

RTU, annunciaters, sequence of events recorder, fault recorder, or electromechanical

relays

Benefits of substation automation integration

Integrated substation automation systems provide improved benefits in the functionality, design,

operation, maintenance and reliability of the substation operating environment. The following

benefits can be seen:


- Standardization of the user interface and improved user access - Elimination of unnecessary redundant equipment. - Reduced substation infrastructure including wiring, conduit, wire channels, control/relay

panel space and control house size. - Easy upgradability using mainstream hardware and software; protocol independence. - Distributed computing and communication hub for simplified integration of distribution

automation (DA). - Uniform HMI for data access. - Interoperability of IEDs. - Integrated alarm log and sequence of events reporting. - Custom display and reporting capability from integrated database. - Automatic logging of HMI accesses and operating activities. - Programmed logic for automatic reconfiguration of busses and/or feeders. - Network messaging between substation server nodes and other WAN nodes. - Data for relaying, metering and communication service is available locally or remotely. - Predictive maintenance is possible from automatic analysis of equipment operating

history. - Supervision and management of transformer, load tap changer, and circuit breaker

internal operations optimises just-in-time maintenance. - Uniformity and consistency in HMI operation procedures reduces the chances for

operating errors. - Integrated and sequenced databases provide accurate information for problem analysis

and maintenance. - Monitoring of all station equipment ensures that failed equipment is detected and

repaired before called upon for service during system disturbances. - Reduced customer outage minutes resulting in improved reliability indices. - Reduced chances for operator switching errors. - Quick isolation of faults and restoration of service to unfaulted feeder sections. - Reduced costs for new construction. - Reduction of unnecessary trips to read alarms, relay targets, and station logs. - Readily accessible relay operation information, fault location data and alarm log for

operators will help reduce line patrolling and problem investigation time, and thus outage time.

- Reduced training costs because of uniform database, H M I, customized screen format tailored for ease of use.

- Integrated database information, comprehensive problem reporting and a future expert system can greatly facilitate of maintenance and repair activities, thus reducing costs.

- Maintenance scheduling can be streamlined and optimised for a cost effective and efficient program, by using the ad documentation.

- Distributed computing hub to manage the substation and connected feeder environment - Shared access to the enterprise WAN by SA and DA devices.

6. The functions of substation automation

Process Connection

Each control and monitoring system needs input data from the process, and outputs to control

the process. This process interface is the connection between the switchyard - the process to be

monitored and controlled - and the substation automation system (Figure 1). On one hand the

process interface allows to transfer information from the SA system to the process and vice


versa, on the other hand it is the barrier between the control system equipment and the hostile

environment of the process.

Fig. 1: Process connection between HV switchyard and substation automation system

The high level of electromagnetic disturbances led classically to interface solutions with relatively

high voltages and currents as physical transfer medium between process and SA system. To

save power as well as cabling effort and space, the latest developments allow to locate

electronic sensors for voltage, current and gas density measurements as well as for position

indication, and actuators for switchgear control like circuit breakers and disconnectors into a

shielded box directly integrated into the switchgear, so called "intelligent" primary equipment In

this case a serial bus interface (normally an optical process bus) can be considered as the

process interface (Figure 2). Since the shielded boxes provide some functionality, at least the

A/D conversion and serial communication, they act at least similar to conventional I/O cards.

Pre-processing of data for maintenance purposes and more functionality can be added.

Therefore, the process interface is moved directly into the process, i.e. to the switchgear.

Another change regarding the process interfaces is the introduction of non-conventional sensors

and actuators, e.g. based on fibre optics to generate optical signals that are related to the

magnitude of the primary current rather than a magnetically transformed current. To make signal

processing not complicated, all these non-electrical sensors should produce signals that are

directly proportional to the primary source signals. Non-conventional actuators allow operating

the drives of the switching devices directly via a serial link also (optical process bus).


Fig. 2: Process connection between intelligent primary equipment and substation

automation system

Fig. 3: Process connection to a typical IED BI Binary Input; BO Binary Output; AI Analogue Input; FI Filter; AD Analogue/Digital

Converter


Conventional Sensors and Actuators

The most important inputs from the process are the currents and voltages from different places

in the switchyard, and the positions of switches and transformer tap changers. The most

important outputs are the control of switches and tap changers. Additionally other physical

quantities like temperature, gas pressure etc. has to be monitored, and binary as well as

analogue control outputs to different other equipment may be necessary.

This leads conventionally to the following kinds of sensors and actuators respective interfaces to

them (Figure 3):

Currents and voltages from the switchyard:

Current transformers (CT) and voltage transformers (VT) directly located in the switchyard

deliver currents in ranges from 0 to 1 A or to 5 A, respective voltages in the order of 100 or 200

V AC. Voltage transformers are sometimes also called Potential Transformers (PT).

Switch positions

Auxiliary switches are mechanically connected with the main contacts. With the help of the

station battery (auxiliary voltage) of 100/110/220 V DC they deliver binary information to the SA

system. A switch position is normally indicated by two contacts: one is closed if the switch is

closed, and a second one is closed if the switch is open.

This double indication shows a moving switch in the so-called intermediate position if both

contacts are open. For disconnectors and earthing switches it is physically impossible that both

contacts are closed at the same time in normal operation, so this must be regarded as an error.

The same is true for the intermediate position, if it lasts longer than the switch movement time

(often called running time). For circuit breakers in high voltage switchyards often each of the

three phases has its own drive. It may then happen that one phase is in a different state than the

others (phase discrepancy). If the contacts of the phases are connected in parallel (Iogic OR) to

get one double indication again, then the 1-1 state may happen, and may be cleared e.g. by an

open command. If however this state lasts too long or can not be cleared, then again this is a

serious error (permanent pole discrepancy).


Other indications or alarms

Similar auxiliary switches like for switch positions are used, but each indication has one contact

only: single indication.

Commands

Tripping or closing coils have to be supplied with power. Again normally a process auxiliary

voltage in the range of 100/110/200 V DC is used, and up to 1 A currents have to be switched by

the auxiliary contacts.

For other physical quantities special sensors are used, which normally deliver proportional

outputs in the range of 0...20 mA or +-10 V. Other ranges (e.g. 0...10 mA 0...20 V) are also

sometimes used. For sensor failure supervision 4...20 mA is also often used, where 4 mA

corresponds to a physical value of 0, while 0 mA indicates that the sensor has failed, e.g.

because of a broken wire. These electrical quantities have to be fed into the SA system, and

there encoded into binary information, which is suitable for further processing.

Instantaneous analogue process inputs (current voltage)

The analogue process inputs are transferred to a suitable signal range by appropriate signal

transformers, which additionally provide the galvanic isolation from the process. The analogue

signals are filtered by an antialias filter, which suppresses multiples of the sampling frequency,

and finally converted to binary samples by means of an A/D converter (Figure 3). Also high

frequency damping filters are sometimes used to suppress disturbing spikes, depending on the

function to be performed. After this conversion further filtering with digital filters is made if

necessary. Important criteria here are the accuracy of the A/D conversion related to the

measuring range, and the sampling frequency. Both, amplitude and phase relations are needed.

If different phases must be compared, then they need a time synchronization accuracy in the

order of so me microseconds, providing the accuracy needed by the functions considered. A

timing jitter of 25 µs leads to an accuracy of about 2 %. The information content of samples may

be also represented as phasors, i.e. as a value with an amplitude and a phase angle with the

same accuracy.

Other analogue inputs

Because of electromagnetic disturbances the current or voltage inputs have to be galvanically

isolated, e.g. by isolation amplifiers, before they can be fed directly to an A/D converter. The


needed sampling rate is normally much slower than for the voltage and current inputs. Most of

the sensors have a linear characteristic, but for some of them a non-linear characteristic has to

be applied to get the correct physical value (non linear scaling).

Binary process inputs

The process voltage, which indicates either an open or a dosed contact, is normally connected

to optical couplers for galvanic isolation (Figure 3). Thereafter a discriminator determines the 0

or 1 state. Note that the 1 state may denote a closed contact (normally open, NO-contact) as

well as an open contact (normally dosed, NC-contact). The contact inputs may be grouped to

double indications or, e.g. in case of transformer tap changer position, to multiple indications

representing digital numbers.

Binary process outputs

Binary command outputs to the process are performed via relays whose contacts can directly

switch the trip/dose coil currents, so called heavy-duty contacts (Figure 3). The problem here is

that these contacts may burn or melt together, if they switch relatively high currents. These

command outputs are safety critical, because an unintended operation of a switch may cause

physical damage or endanger human beings. To minimize the risk two separate output channels

that are connected in series must be used to supply the operating coil current. In line with the

former RTU based solutions one is called the Select channel, which selects the switch, and the

other Execute channel, which switches the load current. Both contacts have to be supervised, so

that a relay (contact) failure is detected before any second failure may happen.

Other binary outputs

Other binary outputs may be provided for local or remote state and alarm indications. For these

outputs signalling relays are used, which are normally not safety critical and must switch only

low currents in the mA range.

Analogue outputs

For analogue outputs normally ±10 V or ±20 mA outputs are used. If an electromagnetic

interference (EMI) barrier is necessary, additional separating amplifiers are provided. In a

modern substation, there is normally no need for analogue outputs, as mostly serial interfaces

and LCD or Led based displays are used.


Analogue data from unconventional sensors

Unconventional sensors for voltage and current are not based on the magnetic transformer

principle but on electro-optical effects. Their output is either an optical amplitude or the plane

angle of polarized light modulated according to the AC voltages and currents from the electric

power process. Semi-conventional devices are capacitive voltage dividers providing a small

voltage signal proportional to the AC process voltage. Rogowksi coils provide di/dt according to

the AC process current and need an integration algorithm to obtain the current signal. Common

to all these sensors is that they do not provide the common signals of the order of 1 A, 5 A, 100

V, or 200V, partly no electrical signals at all. Converting the outputs to small electrical signals is

possible, but small signals are both subjected to electromagnetic interferences and not compa-

tible to conventional EDs e.g. for protection. To overcome these problems, the most convenient

way is to provide these signals as telegrams over a serial link (optical process bus).

Binary data from unconventional sensors

Also binary data may be produced by sensors as optical or low level electrical signals not fitting

into the 110/220 V DC scheme. The most convenient way again is to provide these signals as

telegrams over a serial link (optical process bus).

Binary process outputs to unconventional actuators

The principles of unconventional actuators integrated into the switchgear are very dedicated

depending on the type and design of controlled equipment. The common interface is again the

serial link (optical process bus).

Pre-processing of data

Binary data is used for two different purposes: showing the current state e.g. of switches, alarms

etc., and logging of occurred events for later fault analysis. For the second purpose, a time

stamping resolution of 1 ms is required. The time stamping accuracy depends beneath this

resolution also on the device internal time stamping accuracy as well as on the time

synchronization accuracy between different devices. In principle this time stamping accuracy

should therefore also be 1 ms. The accuracy is however very cost sensitive. Depending on the

purpose, accuracy up to 10 ms may be considered as sufficient for some functions.


The pre-processing of analogue values after the conversion from analogue to digital data

depends on the kind of value, and the purpose. The prerequisite in each case is that the

analogue inputs pass through an anti-alias filter in order to prevent any negative impact of the

sampling frequency.

The current and voltage samples are stored into a buffer. Different filtering algorithms may be

applied to this buffer depending on the kind of function, which has to rely on them (mostly

protection). These filtered values may then be used by the various functions. A common

application for measuring purpose is to calculate voltage and current RMS values, frequency,

active and reactive power, as well as the power factor cos ϕ.

The measuring process at a certain point in the process possibly leads to a calculated value like

the RMS values. This value at a certain point of the process, or sometimes this point itself is

called measurand. The following general measurand handling functions refer to electrical

measurements as well as to non electrical measurements from sensors or transducers, but

normally not to the raw sampled values, which are handled specially e.g. by protection functions.

The measurands coming from the A/D converter are some integers, depending on A/D converter

accuracy between 8, today mostly 12 up to 16 bits wide. Application functions need an

application value in some engineering unit. The conversion of the integers to engineering units

(e.g. Volts or Megawatts) is called scaling. The resulting value then normally has a floating-point

data type. Sometimes also calculated values have to be scaled. A power value calculated as

ϕcosUI might already have a floating-point format, but has to be normally scaled to the MW

range. The scaling process has to consider the converter characteristics across the converter

measuring range. Most converters have a linear characteristic, but not all. Therefore, in special

cases also other than linear conversions might be necessary.

If the communication capacity is small and the value must be transmitted as compact as

possible, the sender scales the value down to a minimum number of digits for communication,

and the receiver scales back to the engineering units. If the communication capacity and

processor capabilities are not an issue, then scaling to floating point values is performed as near

to the process as possible, i.e. immediately after A/D conversion and measurand calculation.

The obtained measurands as well as other measurands coming via transducers can be

supervised on warning or alarming limits. Normally two limit pairs (warning and alarm) can be


defined for each measurand, each pair consisting of a low and a high limit. If the measured value

crosses the limit, the value gets an appropriate warning or alarm state attached. This may also

be logged by a time stamped event.

It must be kept in mind that the calculated quantities derived from several measured values

normally have an inaccuracy range in the order of the sum of all the inaccuracies. This is valid

for sums of values, but also a good estimation for products and divisions, if the contributions of

the individual values are in the same order of magnitude as the final value.

7. Operative Functions

Operative functions are all those functions, which directly enable an operator to controI the

substation. These are the typical SCADA functions: Supervision Control And Data Acquisition.

The data acquisition part of SA systems contains some substation specific functions and

performance attributes, which are normally not needed in standard industrial SCADA systems.

The same applies for the specific and safety related switch control functions.

If a network control centre remotely controls a substation, then with the exception of the

communication link to the network control centre only the monitoring and data acquisition

functions of SCADA might be implemented at the substation. This monitoring part could be

completely implemented locally with the possibility of remote operator access to the substation

data. Another possibility is to have only the data acquisition function implemented at the

substation, and the HMI and archiving related functions are located in the remote control centre,

which might cover a number of substations. For special purpose applications like asset

management even a separate remote monitoring centre can be used.

Monitoring and supervision functions

The main purpose of monitoring and supervision functions is:

- to show the state of the process, i.e. the switchyard and the control system itself,

- to inform about the development of possible dangerous situations and,

- to archive data for later evaluation either of the process performance, or for later failure

analysis if same failures or dangerous incidents have occurred.


All those functions except disturbance recording are standard SCADA functions, i.e. they are not

specific for control of substations, although same of their properties like time stamp accuracy of

1 ms are specific for power system applications.

The typical monitoring functions are:

- Event management (Figure 4)

- Alarm management

- Data storage and archiving

- Disturbance recorded fault data retrieval . Log management

Fig. 4: Typical event list

Process state display

There are different methods to browse through the process state of a system:

- Zoom and pan: one can move a window across a virtual picture of the whole system

(panning) and can zoom in an area to see more details, or to get an overview out of an


area receptively navigate to another (sub-)area. This is typically used for big systems or

geographical views in a geographical information system (GIS), and mostly if one wishes

to navigate into a neighbouring area.

- Hierarchical windows: starting from a high level overview window showing the

complete system you navigate with a mouse dick to windows showing the wanted sub

area of the system with more information details. This is typically used if geographical

neighbourship is not so important but you need fast navigation to any sub area or even

specific information categories, and information condensing to higher levels. It is easy to

change the way of presenting information in different layers of the hierarchy.

The following examples iIIustrate the hierarchy window approach.

The actual state of the whole switchyard is shown in a graphical overview, and in more detailed

pictures by means of a single line diagram that contains all substation equipment. This state

typically comprises

- Positions of switches (circuit breakers, disconnectors, earthing switches etc.)

- Voltages (kV) and currents (A) at busbars, lines, and transformers

- Active power (MW) and reactive power (MVAr)

The single line diagram may be enhanced by a busbar coloring function to show in different line

colors whether a part of the switchyard is under voltage, not energized, or earthed. Apart from

this, the different voltage levels can be distinguished with different colors, or parts of the

substation with different power infeeds can be distinguished by appropriate colors.

Process overview display

In contrast to the state display showing the state of one voltage level in detail, the overview

display provides an overview of the whole substation. Only the schematically connected power

sources, loads, and the power flows are shown. This may be combined with a busbar coloring

function as well. One can also combine the overview display and the process state display by

means of zoom and pan functions in the HMI. It should however be considered that some

overview data is normally not displayed on detailed pictures and vice versa.


System configuration display

The system configuration picture displays the state of the control system itself. In the case of

missing data it allows the operator to find the reason of the problem, e.g. a faulted secondary

device or communication link. It shows (group) alarms on device or communication line level,

and allows going from here deeper into detail alarms. It further allows to modify the online state

of the control system, e.g. for maintenance, and to retrieve diagnostic information from the

devices. This display is specific for the actual system.

Event list and handling

The event list contains a time stamped log of all events that have occurred in the system in

chronological order:

- State changes

- Alarms appearing and disappearing Limit violations

- Operator's actions: commands and acknowledges etc

Each event can be directly printed out on a log printer (logger). It contains the time when the

event happened, an identification of the object (device or signal) to which the event belongs, and

the specific signal state, which has been caused by the event.

Due to restricted storage capacity, the event list is often kept in a ring buffer. If the ring buffer is

full the oldest events are overwritten. New events must never be lost, even in the case of power

supply failure. Therefore, all events are also stored on non-volatile storage media. The high

capacity of modern storage devices allows to keep much more events than in the past .

The display function for the event list has often incorporated filtering capabilities. In case of a

failure only those events are displayed which have occurred in the fault related time window or

are identified by a fault expert system.

For power failure analysis a time stamping resolution of 1 msec and accuracy between 1 and 20

ms is needed to assure the chronological order of the events. For power network failure analysis

the same accuracy is necessary between different substations. Therefore, substations are time

synchronized by means of satellite docks like GPS or as often in Europe by radio clocks like

DCF77. In addition to this, the controI system must contain special means for time synchro-

nization of all its devices.


Alarm annunciation and handling

Alarms are generated if a system state requires the attention of the operator. The operator has

to acknowledge the alarm to indicate that he has noticed it. An alarm has the following states

(Figure 5):

- Normal, acknowledged

- Alarm, unacknowledged

- Alarm, acknowledged (persistent alarm)

- Normal, unacknowledged (process alarm state disappeared, pending alarm)

Fig. 5: Alarm acknowledgement state transitions

The last alarm state is also called a "transient" or "fleeting" alarm, as the process alarm state

disappeared before it could have been acknowledged. An authorized operator should only make

a change from unacknowledged to acknowledged. The purpose of alarms is to alert operators

either by activating a horn, flashing lights or symbols on a screen etc.

In order to assure an immediate recognition of alarms they are shown on process displays

additionally to the alarm list. These alarm overview pictures are mostly substation specific. The

alarm list however is a standard representation, which contains an entry for each alarm. This

entry shows as a minimum the time when the alarm happened, the alarm description, and the

current alarm state. The alarm list has similar filtering capabilities as the event list, and addi-

tionally allows acknowledging alarms.


The hierarchical grouping of alarms into function or region specific group alarms together with

the prioritising and filtering provides a quick overview in case of floods of alarms occurring.

These group alarms can be shown on the process overview, process single line pictures, or on

customer specific alarm overview pictures.

Fig. 6: Disturbance record with fault evaluation report

Measuring and metering

The ultimate objective of the normal operation of the power system is to supply power in the

most cost effective way. The analogue data from the process not only shows the current state of

the process, but also provides the input for load and power consumption profiles. For billing

purposes the amount of the power delivered needs to be measured. This function is called

metering, in contrast to measuring, which is mainly used for operator information, plausibility

checks and statistics. Instruments, which measure power for metering and billing purposes, must

fulfil certain legal requirements to assure correct measurements and to prevent manipulation.

The same applies for the data acquisition chain from the instrument transformer up to the billing

application. One of these legal requirements is that data used for billing must be archived for

some years. Another requirement is that the metering process must be certified by legal inspec-


tion to prevent manipulation in the course of the acquisition of the metering data, i.e. it must be

sealed in some way.

Blocking list

There are various situations during operation when it is necessary to block operations.

- For maintenance work it may be necessary to block down-going command.

- In special failure situations it is necessary to block up-coming process indications or

measurands.

- If a mess is printed, or a printer is defect, then explicit blocking of printers is necessary.

- For some maintenance activities the blocking of communication lines may be necessary

by taking them out of use.

For all these explicit blockings there should exist an overview showing which blockings are

currently set, because at first each blocking prohibits some function, and second it is normally

set because of a problem which should be fixed. For this reason there exist graphical blocking

overviews and blocking lists.

The blocking list provides a tabular overview of all blocked objects, and enables to de-block

them. It has similar filtering criteria as the alarm and event list. However, normally its contents

should be short, so that filtering is not necessary.

Disturbance recording (Figure 6)

The disturbance recording function records the instantaneous values (samples) of the currents

and voltages to visualize fast analogue changes around a failure (trigger) for later analysis of

network problems. In some way it is the analogue equivalent to the binary event log. It stores

analogue data sampled with rates of 600 up to 20 000 samples per second, depending on the

time resolution required. Because of the fast response time and high data throughput required,

the recording is normally performed near to the process, and directly after A/D conversion of the

analogue data. In addition to the analogue values, also states of binary signals are sampled and

recorded in parallel input channels if applicable.

The analogue and binary values are constantly sampled and written into a ring buffer. As soon

as a predefined event like a fault has triggered the recording function, the recorded data around

a time window before and after the trigger is frozen in the buffer. Thereafter, another buffer is


activated and the procedure is restarted for a possible next recording. This continues until all

memory buffers are full. In order to avoid 1055 of recorded data the files have to be retrieved

and stored somewhere else, e.g. on a station level hard disk or transmitted to a remote

substation monitoring system. Dedicated evaluation software is used to view the recordings and

to conduct fault evaluations like the determination of the distance to a line fault to ground.

Archiving

Event logging and disturbance recording files are used in conjunction with archived fault history

for failure analysis. Additionally, also the power system performance during normal operation

can be archived for performance analysis and planning purposes. Typical information for this

purpose is the consumed power per minute, hour, day or even Ionger, trends of power

consumption, temperature profiles etc. This archiving activity is done either cyclically or event

driven in so called history buffers. Here also the problem of restricted storage place has to be

considered in so me way, e.g. by means of data condensing hierarchies like minute values per

hour, hourly values per day, daily values per month etc.

The archived data can be used to create reports and trend diagrams, which can be shown on

the screen or printed as hardcopy. Apart from this, dedicated evaluation programs needed for

special analysis tasks may require a data import/export function with a standardized format for

the data exchange between the substation automation system and these programs.

Control Functions

Control functions are used for the normal day to day operation of the substation. They are

performed via an HMI (human machine interface, e.g. screen and keyboard) that is located

either locally in the substation or even in the bay, or remotely at a network control centre. The

HMI presents the process state to an operator and enables him to controI the process. The

response time of the operational functions and the correlated communication is typically a

second (human ready on time scale). It is often distinguished between monitoring and

supervision functions that retrieve data from the process for performance analysis, and the

control functions that initiate actions on the process. Nevertheless monitoring and process state

display is the prerequisite for conducting substation control.

Commands that directly controI the process can cause severe damage if they are issued

wrongly. Therefore, control functions have to be protected against unauthorized access, and

safeguarded that no dangerous and unnecessary or unprompted commands can be issued.


Examples of such safety related control functions are:

- Access control and operator identification

- Operative mode control

- Control of switches (commands and back-indications)

- Control of transformers (raise/lower commands on tap changer, tap position)

- Management of spontaneous change of positions

- Parameter setting

Protection and safety related functions

Protection and safety related functions need to be fast and autonomous, and they interact

directly with the process and the process data without the interference of the operator. This

means on the other hand, that they must work safe and reliable. The dedicated functionality (i.e.

without data acquisition or operator interface) relates either to a specific piece of primary

equipment or to a bay. The processed data belong either to the specific primary equipment or to

a bay. There is an HMI provided for parameterisation, or for disabling and enabling of the

function. In principle three classes of these functions can be distinguished:

- Protection: this is the active safety level, which supervises the process for dangerous

situations and responds to clear them by tripping the associated circuit breaker(s).

- Interlocking: This is a passive safety level for all kinds of commands. It identifies

dangerous operations and blocks commands, which might become dangerous.

- Automatics: these are sequences of actions performed automatically, after some trigger

impulse has started them. They may be triggered either by an operator or by another

automatic function like protection, or by the process condition supervision. In the last

case, normally the condition supervision is an integral part of the automatic function.

Each automatic function should have its own safety checks, and reside on the top of

underlying interlocking and protection functions.

Distributed automation support functions

Distributed automation support functions are operating with data directly from the process and

supply decision data to other functions, which ad directly locally on the process without the

interference of the operator. In contrast to the local process automation (support) functions they

use input data from the whole switchyard. The core functionality (i.e. without data acquisition or


HMI) uses data from several bays. There is an HMI for parameterisation, or for disabling and

enabling of the function.

There are essentially two automatic support functions:

- Distributed synchrocheck,

- Station wide interlocking.

Distributed Synchrocheck

Distributed synchrocheck is essentially the same function as the local synchrocheck, however

the data of at least one voltage transformer is coming via the communication system. This may

be the voltage from the busbar, or from another bay, if no voltage transformers are available at

the busbar (respective not on all bus bar segments). The determination of which VT has to be

taken to obtain the correct busbar voltage is often called busbar image.

Traditionally one synchrocheck device was used per substation or voltage level. For closing a

circuit breaker with synchrocheck the corresponding line voltage VT output as well as the bus

bar voltage VT output were connected via relay contacts to this synchrocheck device. The result

of the voltage comparison was fed back to all bays inclusive that one concerned. This VT output

switching was rather dangerous and had to be made in a very controlled and supervised way,

because if accidentally two VT outputs were connected, the VTs could be destroyed. Using this

hardwired solution, power may be accidentally fed back from the loaded to the unloaded line.

With the numerical bay level protection or control devices the synchrocheck became a function

at each bay, where the bay VT output can be directly connected to these devices. Nevertheless,

the output of the busbar VT providing the busbar voltage either direct or via a busbar image

remains to be switched to the appropriate bay.

New fast and high capacity communication media nowadays allow transferring the needed

busbar voltage across the communication bus in digital form, avoiding any needs for physical

switching. Due to the time delay caused by the communication special means are however

necessary to synchronize the time of the voltage data retrieved from the two sources, bay and

busbar, with accuracy around 20 !!s.

The upcoming communication standard IEC 61850 will be an enabler for the implementation of

this cost effective function, as it has the features to achieve this accuracy and to provide the

necessary communication bandwidth in a standardized way.


Busbar image

If the busbar voltage transformer has been omitted in the switchyard to save costs in the primary

system, a busbar image function has to be applied to determine which line is actually connected

to the busbar. The VT of this line is taken as the busbar voltage source e.g. for synchrocheck or

for the busbar voltage measurement. This busbar image is based on the topology of the

substation single line, i.e. the momentary state of all switches as well as their static connections.

This busbar image can naturally also be used to determine the voltage at the busbar, even if

there is no busbar VT available, and to show this calculated busbar voltage at station level.

System Configuration and Maintenance Functions

A substation automation system normally consists out of a set of standard software packages,

running on a distributed system, and a lot of substation and customer specific configuration data,

function parameters, and specifically developed software. In the ideal case all software is stable,

and any necessary adaptations during operation or for eventual later system modifications and

extensions can be just done by configuration and parameterisation; this means by adaptation of

the appropriate data, which describe the switchyard, the controI system and its functions, and its

connections to its environment. The system configuration and maintenance functions are a sub-

set of the engineering functionality, which is needed during commissioning, and during operation

and maintenance of the system. In any case these functions must mark all the objects (data or

software) describing a system instance with revision information. This must as a minimum

identify the revision and contain the date of the last change. As this is normally not done for a

single item of a configuration data base, this data must be structured into entities with a common

purpose, which then have a common revision index. This allows to track changes during the life

time of the system.

System Configuration and Adaptation

The system configuration consists of all data describing the individual configuration of a system.

It excludes those data, which are normally changed / adapted during operation. In some cases,

e.g. for the limits of certain measurands, it might depend on the operation philosophy of the

customer if these are operational parameters or configuration parameters. Configuration

parameters normally have to be restored during replacement of hardware, and they are changed

only, if the system is modified or if they contain errors. Therefore the structuring of configuration

parameters as well as their physical storage often follows the physical structure of the auto-

mation system, and only within this structure, there might be function related substructures.


Additionally to this structure there must exist a system configuration description, which contains

the system related configuration data holding the single IEDs together in the system.

Application Software Upgrade and Maintenance

It may happen, that errors found in a base software package cause a replacement by a newer

version, or that the new hardware implemented after a hardware defect is not 100 % compatible,

so that other drivers or a newer operating system version has to be installed. Sometimes these

modifications can be done on top of the existing system. But mostly the replacement of so me

base software requires a reinstallation of all correlated packages, and especially of the system

specific data.

It is important,

- that these new versions of a functional package are compatible with the rest of the

system software and data,

- and that a systematic backup process and installation procedure allows to re-install the

complete system software and system configuration data afterwards.

For application related functions, the standardization of parameter formats and archiving in an

implementation independent way can also lead to better upward compatibility in case that new

software versions of the application have to be installed.

8. Communication Functions

Communication functions are support functions, which are necessary due to the fact, that

- either the system is widely distributed and the communication performance is not

sufficient when all functions would individually and directly access the same data source,

- or devices from several manufacturers or different implementation generations have to

be connected with different protocols.

Data Exchange within the Substation

Data exchange within the substation is needed in distributed systems, or for coordination

purposes within redundant systems, respectively between parts that have been physically

separated because of reliability reasons. A typical communication function within the substation


enables data exchange between the control devices or the station level devices at one side, and

the protection devices on the other side.

Data Exchange with External Systems

The data exchange with external systems is the classical task of Remote Terminal Units (RTUs),

and the Network Control Centre (NCC) is the classical external system. This data exchange

functionality has been allocated to the gateway function of modern SA systems. It provides

binary and analogue process related data as well as time stamped events for a network control

centre. A control coordination, data concentration and data filtering, perhaps in specially

designed firewalls, will always remain.

New functionality and new needs lead to a second kind of wide area connection directly to

substations: connections from maintenance centres.

Supervisory Control and Data Acquisition (SCADA)

The term SCADA is used for the basic data acquisition, supervision and control functionality of

any control system. and therefore is also the basic functionality of an SA system. This func-

tionality naturally supports the appropriate SCADA functionality at network control level. In some

cases the network control centre can even shrink to a set of remote terminals at the SA systems.

At present, it is normally the other way around, i.e. the SA system is the data acquisition part for

the NCC.

Power Application Software (PAS)

The term "Power Application Software" is used for all applications that support the network

operation of a power system under normal working conditions, and these applications run

normally in network control centres (NCC). The SA system delivers the basic data needed for

the power application functions like RTUs to NCC systems for energy management (EMS),

automatic generator control (AGC), energy scheduling etc. The performance of the data

transmission has to be tuned according to the functional needs. AGC e.g. requires only a few but

critical measurands with a maximum allowed data age of 4-10 s. If the NCC communication

cycle time is in the order of 3 s, then this data must be available at the SA gateway function not

later than every second. On the other side, each central function can in principle be distributed to

a lower level, if the devices at this level are interconnected with sufficient communication

capacity.


9. Substation automation structure

The station level provides the Human Machine Interface'(HMI) as central place for substation

operation. This is normally located in a central room, which should be shielded against

electromagnetic disturbances from the switchyard. Further also all general purpose hardware.

screens and printers are concentrated on station level. This commercial equipment needs air

conditioning and AC supplied by a special uninterruptible power supply (UPS). The rest of the

substation works with 110 or 220 V DC, which is supplied by the station battery, directly in the

switchyard environment. Consequently, all general management and station level functions like

event logging and printing, archiving and history data storing are located at station level, as well

as more complex station level automatic functions that can easier be implemented on powerful,

general purpose computers.

Fig. 7: Operator workplace

Also the interfaces for the communication with remote centres for network control, monitoring or

maintenance are usually physically located at the station level. The station level equipment is

often separated into two rooms:

- the operation room providing comfortable working conditions and noise protection for

operators is equipped with the Human Machine Interface that consists of screens,


keyboards, tablets or mice, printers, and in earlier times also a control panel (Figure 7),

and

- a communication equipment room, where the computers, backup printers, and

communication equipment reside, which may be more noisy.

Due to the miniaturization of electronics the PC hosting the HMI software can also run parts of

the operational and communication software, so that this PC is normally located in the operation

room. In case that this also applies for the telecommunication equipment, all can shrink down to

one room only, where the equipment may be integrated in one desk.

Human Machine Interface (HMI)

The human machine interface (HMI) serves to operate and supervise the substation. In modem

substation automation systems it comprises one or several operator places. Each operator place

has one or, in rare cases, even two to three screens, a keyboard, and a mouse. Sometimes also

functional keyboards or graphical tablets are used, but the mouse in combination with dive

buttons on the screen pictures is more and more standard practice, so that functional keyboards

are no longer required.

A printer for screen hardcopy and reports supplements the operator place. In earlier times, also

event log printers have been used in order to overcome the limited computer storage capacity by

"storing" event history on paper.

Local Control and Station Level Automatics

Depending on size, complexity, and required reliability, station level automatic functions may

reside on a separate station level. IED with the same reliability and environmental quality as the

bay level lEDs. These functions may also be implemented into the station HMI computer or

another station level general-purpose computer, which then normally needs special measures

like redundancy to obtain the needed availability. If all needed functionality can be concentrated

on one general-purpose computer, the additionalIy needed work places are realized as

terminals, which are associated to this central station level computer. The central station

computer provides the access to the process and conducts the archiving, logging and station

automation fundions. It has to be kept in mind, however, that all station level automatic functions

must be coordinated with the operator's actions whether taken on station or on bay level.


Substation Database and Archive

The large storage capacity that is available on station level by means of hard disks, tapes and

nowadays CDs, naturally leads to a system architedure, that locates the data archive for all

archiving functions on station level. Also the data for engineering and system configuration as

well as for maintenance are usually stored on this level, if not even higher to allow central

administration for a lot of substations. Depending on the purpose, either data files or relational

databases are used for data storage. Because of performance requirements actual process

status data is very often held in manufacturer specific real time databases implemented in the

RAM memory. New technologies like objed oriented databases, OPC (OlE, Le. Object Linking

and Embedding, for Process Control) for process data access, as well as the increasing

computer performance will change this present practice resulting in an object oriented data

storing concept that provides data access via multiple views respective different usage aspects.

Process Data Access

All station level functions need to have access to the process data. This has to be enabled via

specific communication functions depending on the kind of data to be accessed as weil as on

the communication protocol to be used. In order to decouple the station level functions from the

communication protocol. a process access layer is implemented in between.

In SCADA systems a central process database is typically used provided with relatively slow

wide area communication links. Its state is regularly updated from the process via the

communication system, and the process related information is used by all station level functions.

Industrial control systems with high speed LANs rely in contrast on distributed process

databases that are located in the bay level controllers and are accessed from the station level

functions via LAN.

Time Synchronization

A lot of functions need time stamped data, and time synchranization is therefore a very important

system support function. A lot of different methods for time distribution and time synchronization

are applied. Two general methods can be distinguished:

- Time synchronization via a separate synchronization pulse: This method needs a

separate wire or optical cable for the distribution of the synchronizing pulse once a

second or a minute to all IEDs concerned.


- Time synchronization via communication busses: A master dock that is located at

each communication bus maintains the correct time. The docks of all connected IEDs

that need a synchronized time are synchronized via the master docks. This may either be

done by broadcasting time telegrams from the master dock, or by slave docks that are

regularly asking for the valid time (Figure 8).

Fig. 8: Time synchronization via Interbay bus

10. Substation automation in the near future

If time synchronization is needed between several substations, then a common external master

dock has to be used. This can be located at a network control center to synchronize the docks of

all connected substation automation systems and RTUs. The even more accurate method

mostly applied today is, to use a publicly available radio dock time master for synchronization,

like the GPS satellite system or the DCF77 radio time sender. The corresponding time receivers

are then located in the substations, typically at station level.

Due to the pressure to improve the performance of the power systems in order to satisfy the

ever-increasing demand for electric power, the networks have to be operated closer to the linits

of their power transmission capacity. This, however, causes higher risks for wide area

disturbances to occur due to the lack of reliable assessment of the actual power system stability

limits.

A wide area protection system (WAP), which complements existing protection and control

systems, provides new solutions for the detection of incipient abnormal system conditions early


enough that predetermined defensive actions can be initiated either manually by the operator or

automatically in emergency situations to counteract system instabilities and to maintain power

system integrity (Figure 9).

Fig. 9: Wide area protection and monitoring scheme

Phasor measurement units (PMU) that are installed at critical locations thoughout the

transmission network sample voltage and current phasors to deliver accurate and actual real

time data about the power system stability conditions. They are synchronised via the global

positioning system (GPS) satellites so that simultaneous snapshots of phasors can be taken,

which are collected at the protection centre. This approach allows to measure ba gathering a

large amount of mesurands what has to be estimated otherwise, and it results in power system

state estimation.