CHAPTER 1 1.0 BACKGROUND TO SCADA - University of Nairobieie.uonbi.ac.ke/sites/default/files/cae/engineering/eie/SCADA... · SCADA is an industrial monitoring measurement and control

AYISI VALENTINE F17/8244/04 © 2009 1

CHAPTER 1

1.0 BACKGROUND TO SCADA

1.1 INTRODUCTION.

What is SCADA?

The acronym SCADA stands for Supervisory Control and Data Acquisition.

SCADA is an industrial monitoring measurement and control system. It consists of a central

station, field data gathering elements (RTUs) and a collection of standard and/or custom software

used to monitor and control remotely located data elements.

Contemporarily SCADA system exhibit predominantly open loop control characteristics and

utilize predominantly long distance communication.

Similar system to SCADA systems are routinely seen in factories, treatment plants etc. These are

often referred to as distributed control systems (DCS). They have similar functions to SCADA

systems, but the field data gathering or control units are usually located within a more confined

area. Communications may be via a local area network (LAN), and will normally be reliable and

high speed integrated. A DCS system usually employs significant amounts of closed loop

control. SCADA systems on the other hand generally cover larger geographic areas, and rely on

a variety of communication systems that are normally less reliable than a LAN.

Supervisory refers to the actual seeing and monitoring of the system. Control is the real

operation. It involves the sending and receiving of commands. Data acquisition is the most

important part of SCADA system. It involves the collection of data. Data collected includes:

• Measurements i.e. voltage, frequency, current and reactive power.

• Indications i.e. ON or OFF switches, auto or manual transformers, open or closed CBs.

• Alarms i.e. for system operation


1.2 HOW SCADA WORKS

In most SCADA systems, the master unit sequentially scans the remote terminal units (RTUs),

by sending a message to each RTU to inquire whether the RTU has anything to report. If it does,

the RTU will send a message back to the master, and the data received will be put into the

memory of the computer for processing. The scan of all RTUs in the systems will be completed

in approximately 2s. However, in the event of trouble at a remote station, a message will be sent

from the remote unit to the master. The normal scan will be interrupted long enough for the

master to receive the message and provide an alarm so that the master unit can automatically

perform predetermined control actions. In any event, in most cases, the status of all stations

equipped with RTUs can be monitored every few seconds, providing the operations at the control

center with-up-to-date reviews of the system conditions.

POWER LINE

…..

…..

FIGURE 1.1 GENERAL SCADA SYSTEMS SCHEMATIC

CENTRAL

STATION

TRANSFORMER 1

TRANSFORMER N

RTU 1

RTU X

RTU 1

RTU Y


1.3 SCADA ARCHITECTURES

SCADA systems have evolved in parallel with the growth and sophistication of modern

computing technology. The following sections will provide a description of the following three

generations of SCADA systems:

• First Generation – Monolithic

• Second Generation – Distributed

• Third Generation – Networked

1.3.1 Monolithic SCADA Systems

When SCADA systems were first developed, the concept of computing in general centered on

“mainframe” systems. Networks were generally non-existent, and each centralized system stood

alone. As a result, SCADA systems were standalone systems with virtually no connectivity to

other systems. The Wide Area Networks (WANs) that were implemented to communicate with

remote terminal units (RTUs) were designed with a single purpose in mind–that of

communicating with RTUs in the field and nothing else. In addition, WAN protocols in use

today were largely unknown at the time. The communication protocols in use on SCADA

networks were developed by vendors of RTU equipment and were often proprietary. In addition,

these protocols were generally very “lean”, supporting virtually no functionality beyond that

required scanning and controlling points within the remote device. Also, it was generally not

feasible to inter-mingle other types of data traffic with RTU communications on the network.

Connectivity to the SCADA master station itself was very limited by the system vendor.

Connections to the master typically were done at the bus level via a proprietary adapter or

controller plugged into the Central Processing Unit (CPU) backplane.

Redundancy in these first generation systems was accomplished by the use of two identically

equipped mainframe systems, a primary and a backup, connected at the bus level. The standby

system’s primary function was to monitor the primary and take over in the event of a detected

failure. This type of standby operation meant that little or no processing was done on the standby

system. Figure 1.2 shows a typical first generation SCADA architecture.


1.3.2 Distributed SCADA Systems

The next generation of SCADA systems took advantage of developments and improvement in

system miniaturization and Local Area Networking (LAN) technology to distribute the

processing across multiple systems. Multiple stations, each with a specific function, were

connected to a LAN and shared information with each other in real-time. These stations were

typically of the mini-computer class, smaller and less expensive than their first generation

processors.

Figure 1.2 First generation SCADA architecture

Some of these distributed stations served as communications processors, primarily

communicating with field devices such as RTUs. Some served as operator interfaces, providing


the human-machine interface (HMI) for system operators. Still others served as calculation

processors or database servers. The distribution of individual SCADA system functions across

multiple systems provided more processing power for the system as a whole than would have

been available in a single processor. The networks that connected these individual systems were

generally based on LAN protocols and were not capable of reaching beyond the limits of the

local environment.

Figure 1.3 Second Generation SCADA Architecture


1.3.3 Networked SCADA Systems

The current generation of SCADA master station architecture is closely related to that of the

second generation, with the primary difference being that of open system architecture rather than

a vendor controlled, proprietary environment. There are still multiple networked systems, sharing

master station functions. There are still RTUs utilizing protocols that are vendor-proprietary. The

major improvement in the third generation is that of opening the system architecture, utilizing

open standards and 13 protocols and making it possible to distribute SCADA functionality across

a WAN and not just a LAN.

Open standards eliminate a number of the limitations of previous generations of SCADA

systems. The utilization of off-the-shelf systems makes it easier for the user to connect third

party peripheral devices (such as monitors, printers, disk drives, tape drives, etc.) to the system

and/or the network. As they have moved to “open” or “off-the-shelf” systems, SCADA vendors

have gradually gotten out of the hardware development business. These vendors have looked to

system vendors such as Compaq, Hewlett-Packard, and Sun Microsystems for their expertise in

developing the basic computer platforms and operating system software. This allows SCADA

vendors to concentrate their development in an area where they can add specific value to the

system–that of SCADA master station software.

The major improvement in third generation SCADA systems comes from the use of WAN

protocols such as the Internet Protocol (IP) for communication between the master station and

communications equipment. This allows the portion of the master station that is responsible for

communications with the field devices to be separated from the master station “proper” across a

WAN. Vendors are now producing RTUs that can communicate with the master station using an

Ethernet connection.


CHAPTER 2

2.0. TECHNOLOGY BACKGROUND

2.1 SUPERVISORY AND CONTROL FUNCTIONS

2.1.0 INTRODUCTION

The SCADA system is a general hardware and software concept providing a flexible set of

functions. The actual use of the SCADA system is specified by parameters defined in the

database. This brings down system costs, increases system reliability through its well-proven

design, and makes project development and implementation safe. It further constitutes a basis for

implementing more advanced functions. They provide for further development of the control

system once it has been put into operation. This is a basic requirement since it must be possible

to add new power system components which are going to be monitored and controlled by the

control system.

This chapter gives an overview of the SCADA functions available in control systems today.

First, the collected and processed data are presented and then the basic monitoring and event

handling of these data are described.

2.1.1 Data Acquisition

The basic information with regard to the power system is collected by equipment in the various

substations and power plants. The distributed control system equipment enables remote data

acquisition. Data may also be entered manually or calculated. These data are treated exactly like

the automatically collected data.

Data acquisition operation is required to:

• Read power system measurement data from RTUs into the control computer under

program control.

• Detect and handle data error conditions due to RTU and communication system

malfunctions and noise.


• Scale and convert analogue data into binary form directly usable by the computer

programs.

• Interface with database manager (DBM) that generates data base addresses, and

store data in database.

• Store only error free data, quality indicators should be set to denote error

conditions.

• Complete the scan in minimum possible time before the next scan begins.

1. Status indicators

The status of CBs, indicators, alarm signals and other signals is represented by means of “status

indicators”. These status indications are contact closings connected to digital input boards.

Normally there are both single (1-bit) and double (2-bit) status indications. Double indications

are normally for circuit breakers, disconnectors and other two-state and the other bit represents

the CLOSE-contact and the other bit the OPEN-contact. This facilitates detection of false and

intermediate values.

2. Measured values

Measured values of various kind e.g. voltage levels, active and reactive power flows,

temperature and tap changer positions are collected by the control system. These values then

represent the momentary state of the measuring point. Two types of values are normally

collected.

• Analog values, transformed via an A/D converter o a binary format- supported

without time tag

• Digitally coded values- supported without time tag

3. Energy values

Energy values are obtained from pulse counters. The pulse counting normally involves two

registers: a continuous counter and a time interval register. The pulse counters are frozen locally

in the controlled stations at specified point of time i.e. (when the time expires, a transfer is


initiated from the counter to the time interval register). The generally accepted time is one hour.

Then the counter continues on for the next hour and the register content is collected as part of the

normal scanning. The frozen counter values are reported spontaneously. The included time tag is

the point of time for the freezing.

4. Commands and clock synchronization

Both single and double object commands are supported. Regulating step command is supported.

Set point command and bit string commands are also supported. Clock synchronization is

initially performed according to the procedure defined. However, if the controlling station does

not reply on ‘delay acquisition command’ the controlling station will adapt to that. The clock

synchronization is performed according to the user convention.

2.1.3 Man/Human-machine interface (MMI/HMI)

Man-machine communication is of utmost importance in modern control systems. Few functions

are fully automated, and most require man to interact with the computer system. The design of

the man-machine subsystem involves many ergonomic features that are of equal importance to

the purely technical ones.

MMI is required to provide the following capabilities and facilities:

Ø VDU Displays

The color VDU is the state-of-the-art medium for presenting information to the operator at a

console. The VDU gives the operator an efficient and flexible tool for obtaining as to the

state of the power and control systems. All the data in the system database are available for

presentation on VDU. The only requirement is the specification of a display. This is easily

achieved since it is an inherent function of the modern SCADA system.

Displays objects with power information on the operator console monitor e.g.

§ Online diagrams

§ Alphanumeric tabular displays


§ Lists of various kinds or curve diagrams

Figure 2.1 The main SCADA Display


Ø Data entry

This is via console keyboard. Requirements include:

§ Initiation of control actions

§ Manual data entry into the data base

§ Data entry forms – for passing parameter to a program

All data entry operations may be selected by cursor from menu of options. Interrupt is serviced

from the console hardware and places the console entries into the data entry input queue.

Ø Audible alarms

The audible alarm is the system’s way of notifying the operator about an alarm situation.

Sometimes one audible alarm is shared by the entire control room but often each console has its

own audible alarm, so that activation follows the actual console authority assignment. If the

system implements different priority levels for alarms, this can also be reflected in a set of

audible alarms.

When power system goes into an emergency state an alarm condition occurs. Once it occurs, it

must be properly detected and identified. The operator should be notified with a short message

displayed on the monitor. This message must contain sufficient information to enable the

operator identify the alarm condition, evaluate its threat to security of the power system, and

decide on the corrective measure to be taken.

An important definition task is to define the alarm condition to be checked and determine where

and how to perform alarm condition detection and identification.

Ø Printer outputs

The operator normally obtains information about the state of the power system via the VDUs of

the consoles. For permanent records of the state, various output units are introduced in the

system configuration. The documents produced are used for operational follow-ups,

documentation purposes and maintenance of the control system database.


2.1.4 Performance monitoring

Performance monitoring function is required to enhance the operational availability of the

SCADA system.

Response time is the manifestation of control system performance as seen from the operator’s

point of view. Response time is defined as the time from the request of a function until the

complete result of the function is ready. The requirements on system response time of showing

data to the operators, or of performing control commands, greatly affect the design of the system

and need to be looked into deeply.

The reason why response time is important is that long delays cause stress and are very annoying

to the operator. Stress is caused by disruption of the operator’s thought process. Humans in a

problem solving situation use the short term memory of their brains. This short-term memory is

characterized by low capacity and high volatility.

A basic requirement (and design goal) is that the availability of SCADA system, its

communication system and RTUs must be greater than the corresponding availability of the

power system network. That is, to be of value, the SCADA system must remain in operation

during power system outages, faults, and failures caused by electrical and mechanical

malfunctions or hostile environment conditions.

Basic philosophy of performance monitoring is that any single fault within the SCADA system

shall neither stop the system from operating nor disturb the power system.


2.2 Components of SCADA system

2.2.0 Introduction.

In order for the aforementioned functions to be achieved a clear understanding of the following

factors that relates to the components becomes critical:

I. Components capabilities and limitations

II. Functional and design features (definition and evaluation)

III. Environmental and functional requirements

IV. Operational timeline and resource utilization

V. Future functional expandability requirement

Generally there are three basic components of a SCADA system; they are:-

2.2.1 Remote terminal unit (RTU)

The remote terminal units (RTUs) read status and information from the power system process,

report changes and information to the central system and execute commands received from the

central system. They have developed in steps from pure hardware units to flexible

microprocessor based units. The basic feature which has made it possible to realize a remote

terminal unit is storage of data. The collected data may then be processed in different ways

leading to advanced RTUs in terms of functional content. The RTU may serve as a filter

performing functions which refine data aimed for the central system.

The acquisition and control normally found are:

• Collection of: indications, analog values and digital values

• Collection and accumulation of energy counting pulses

• Output of: On/Off controls, Increase/decrease controls, set point values

By using the basic features, data storage and data queuing more advanced functions can be

realized.


More autonomous RTUs and those having a large functional content have more software, and

software which can be changed, giving the RTU a certain functional content or adapting the RTU

to various environments.

The remote terminal unit (RTU) with power supply, meter sensors, actuators, controlling

electronics and communication interface are directly interfaced to the power line through a PLM.

Features

ü Has a modular and streamlined architecture which simplifies both trouble-shooting and

expansion in the field.

ü They generate analogue and digital signals that will be monitored by the central station.

ü They are normally installed in the meter box and store data in a non volatile memory.

Version for both single and three phases are available.

ü In a place where meters are nucleated multi-meter interface unit (MMIU) is used. This is

an interface that can manage up-to 16 electric meters each with dedicated line, and all

with a shared earth.

ü They are intelligent devices, which collect, process and record power consumption data

from electric meter y picking up the meter-pulse output, converting it to suitable digital

format for data processing. They have relay capability in that they resume normal

operation when power returns after a failure.

ü They have alarm to warn of an impending power interruption.

RTU architecture

The RTU hardware consists of the following main units:

• Central processing unit (CPU)

• Memory

• I/O interface

• Communication interface

• Power supply


These units or hardware elements can be configured in various structures. The final structure

depends on the size of the RTU, as well as the requirements and functions implemented, i.e. the

actual use of the RTU.

Functional adaptability can be achieved as the functional content generally is determined only by

the software. Some RTU functions may require additional hardware, but a modularized concept

will support such configuration changes.

All intelligent logic and communication functions are included in a single integrated processor

card. Field wiring is controlled directly to terminal block monitored on primary types; status,

input control, analogue input panel, analogue output panel and control output panel.

The I/O panel has a bus address and occupies a single daisy-chained ribbon cable bus to the

central processor. Expansion of the RTU requires only the addition I/O panel and re-trapping the

central processor panel to define the new print count, no firmware changes are required in the

remote central processor.

Power line network

Figure 2.2 RTU architecture

Communication I/O

Micro-processor

Data control I/O

Data memory Program memory


Figure 2.3 Typical SCADA system

The kernel of flexible SCADA is to provide a flexible and effective platform of data exchange

and function coordination. “Flexible” means than the SCADA system is not a point-to-point

communication of fixed path, but a communication that can take place between (among) any

random two (or more) points at any time. The main functions can be described as follows:

a) providing data exchange and data share among independent system

b) providing function coordination and result interaction among independent system

c) providing data exchange and data share in different locations in distributed system


d) providing function coordination and result interaction in different locations in distributed

system

Figure 2.4 Structure of flexible SCADA system


2.2.2 Communication network

The communications network is intended to provide the means by which data can be transferred

between the central host computer servers and the field-based RTUs. The

Communication Network refers to the equipment needed to transfer data to and from different

sites. The medium used can either be cable, telephone or radio.

The use of cable is usually implemented in a factory. This is not practical for systems covering

large geographical areas because of the high cost of the cables, conduits and the extensive labor

in installing them. The use of telephone lines (i.e., leased or dial-up) is a more economical

solution for systems with large coverage. The leased line is used for systems requiring on-line

connection with the remote stations. This is expensive since one telephone line will be needed

per site. Dial-up lines can be used on systems requiring updates at regular intervals (e.g., hourly

updates). Here ordinary telephone lines can be used. The host can dial a particular number of a

remote site to get the readings and send commands.

Remote sites are usually not accessible by telephone lines. The use of radio offers an economical

solution. Radio modems are used to connect the remote sites to the host. An on-line operation

can also be implemented on the radio system. For locations where a direct radio link cannot be

established, a radio repeater is used to link these sites.

Historically, SCADA networks have been dedicated networks; however, with the increased

deployment of office LANs and WANs as a solution for interoffice computer networking, there

exists the possibility to integrate SCADA LANs into everyday office computer networks.

The foremost advantage of this arrangement is that there is no need to invest in a separate

computer network for SCADA operator terminals. In addition, there is an easy path to integrating

SCADA data with existing office applications, such as spreadsheets, work management systems,

data history databases, Geographic Information System (GIS) systems, and water distribution

modeling systems.


2.3 SCADA Protocols

In a SCADA system, the RTU accepts commands to operate control points, sets analog output

levels, and responds to requests. It provides status, analog and accumulated data to the SCADA

master station. The data representations sent are not identified in any fashion other than by

unique addressing. The addressing is designed to correlate with the SCADA master station

database. The RTU has no knowledge of which unique parameters it is monitoring in the real

world. It simply monitors certain points and stores the information in a local addressing scheme.

The SCADA master station is the part of the system that should “know” that the first status point

of RTU number 27 is the status of a certain circuit breaker of a given substation. This represents

the predominant SCADA systems and protocols in use in the utility industry today.

Each protocol consists of two message sets or pairs. One set forms the master protocol,

containing the valid statements for master station initiation or response, and the other set is the

RTU protocol, containing the valid statements an RTU can initiate and respond to.

In most but not all cases, these pairs can be considered a poll or request for information or action

and a confirming response.

The SCADA protocol between master and RTU forms a viable model for RTU-to- Intelligent

Electronic Device (IED) communications. Currently, in industry, there are several different

protocols in use. The most popular are International Electro-technical Commission (IEC) 60870-

5 series, specifically IEC 60870-5-101 (commonly referred to as 101) and Distributed Network

Protocol version 3 (DNP3).

2.3.1 IEC 60870-5-101

IEC 60870-5 specifies a number of frame formats and services that may be provided at different

layers. IEC 60870-5 is based on a three-layer Enhanced Performance

Architecture (EPA) reference model (see Figure 4.1) for efficient implementation within RTUs,

meters, relays, and other Intelligent Electronic Devices (IEDs). Additionally, IEC

60870-5 defines basic application functionality for a user layer, which is situated between the

Open System Interconnection (OSI) application layer and the application program.

This user layer adds interoperability for such functions as clock synchronization and file

transfers. The following descriptions provide the basic scope of each of the five documents in the

base IEC 60870-5 tele-control transmission protocol specification set.


Standard profiles are necessary for uniform application of the IEC 60870-5 standards. A profile

is a set of parameters defining the way a device acts. Such profiles have been and are being

created. The 101 profile is described in detail following the description of the applicable

standards.

• IEC 60870-5-1 (1990-02) specifies the basic requirements for services to be provided by

the data link and physical layers for tele-control applications. In particular, it specifies

standards on coding, formatting, and synchronizing data frames of variable and fixed

lengths that meet specified data integrity requirements.

• IEC-60870-5-2 (1992-04) offers a selection of link transmission procedures using a

control field and optional address field; the address field is optional because some point-

to-point topologies do not require either source or destination addressing.

• IEC 60870-5-3 (1992-09) specifies rules for structuring application data units in

transmission frames of tele-control systems.

IEC 870-5-101

IEC 870-5-102

IEC 870-5-103

IEC 870-5-5

IEC

EC 870-5-1

IEC 870-5-1

Figure 2.5 Enhanced Performance Architecture

Application Layer (OSI Later 7)

Link Interface

Link Layer (OSI Layer 2) LLC- Lake Layer

MAC- Lake Layer

Physical Interface

Physical Layer (OSI Layer 1)


These rules are presented as generic standards that may be used to support a great variety of

present and future tele-control applications. This section of IEC 60870-5 describes the general

structure of17 application data and basic rules to specify application data units without

specifying details about information fields and their contents.

• •IEC 60870-5-4 (1993-08) provides rules for defining information data elements and a

common set of information elements, particularly digital and analog process variables

that are frequently used in tele-control applications.

• IEC 60870-5-5 (1995-06) defines basic application functions that perform standard

procedures for tele-control systems, which are procedures that reside beyond layer 7

(application layer) of the ISO reference model. These utilize standard services of the

application layer. The specifications in IEC 60870-5-5 (1995-06) serve as basic standards

for application profiles that are then created in detail for specific tele-control tasks.

Each application profile will use a specific selection of the defined functions. Any basic

application functions not found in a standards document but necessary for defining certain tele-

control applications should be specified within the profile. Examples of such

Tele-control functions include station initialization, cyclic data transmission, and data acquisition

by polling, clock synchronization, and station configuration.

The Standard 101 Profile provides structures that are also directly applicable to the interface

between RTUs and IEDs. It contains all the elements of a protocol necessary to provide an

unambiguous profile definition so vendors may create products that interoperate fully.

2.3.2 DNP3 Protocols define the rules by which devices talk with each other, and DNP3 is a protocol for

transmission of data from point A to point B using serial communications. It has been

20 used primarily by utilities like the electric companies, but it operates suitably in other areas.

The DNP3 is specifically developed for inter-device communication involving SCADA

RTUs, and provides for both RTU-to-IED and master-to-RTU/IED. It is based on the three-layer

enhanced performance architecture (EPA) model contained in the IEC 60870- 5 standards, with

some alterations to meet additional requirements of a variety of users in the electric utility

industry.


DNP3 was developed with the following goals:

• High data integrity. The DNP3 data link layer uses a variation of the IEC 60870-5-1

(1990-02) frame format FT3. Both data link layer frames and application layer messages may be

transmitted using confirmed service.

• Flexible structure. The DNP3 application layer is object-based, with a structure that

allows a range of implementations while retaining interoperability.

• Multiple applications. DNP3 can be used in several modes, including:

1. Polled only

2. Polled report-by-exception

3. Unsolicited report-by-exception (quiescent mode)

4. Mixture of modes 1. Through 3

It can also be used with several physical layers, and as a layered protocol is suitable for operation

over local and some wide area networks.

• Minimized overhead. DNP3 was designed for existing wire-pair data links with operating

bit rates as low as 1200 bit/s and attempts to use a minimum of overhead while retaining

flexibility. Selection of a data reporting method, such as report-by exception, further

reduces overhead.

• Open standard. DNP3 is a non-proprietary, evolving standard controlled by a users group

whose members include RTU, IED, and master station vendors, and representatives of

the electric utility and system consulting community.

A typical organization may have a centralized operations center that monitors the state of all the

equipment in each of its substations. In the operations center, a computer stores all of the

incoming data and displays the system for the human operators. Substations have many devices

that need monitoring (are circuit breakers opened or closed?), current sensors (how much current

is flowing?) and voltage transducers (what is the line potential?). That only scratches the surface;

a utility is interested in monitoring many parameters, too numerous to discuss here. The

operations personnel often need to switch sections of the power grid into or out of service. One

or more computers are situated in the substation to collect the data for transmission to the master

station in the operations center. The substation computers are also called upon to energize or de-

energize the breakers and voltage regulators.


CHAPTER 3

METHODOLOGY

3.0 General Scope and Performance Requirements

3.1 General

This section describes the SCADA and Telecommunication system supplied to K.P.L.C. The

intent of the specification is to fully describe KPLC’s needs for the SCADA and

telecommunication system. The telecommunication system supplied satisfies KPLC’s

communication requirements for operational purposes i.e. for operational telephony and SCADA

data transmission. It consists of power line carrier (PLC), fibre optic and radio links together

with all telephone and data transmission equipment required.

Present hierarchical structure of network supervision

Real time control of the electrical network in Kenya is hierarchically structured and basically consists of

three levels.

3.1.1 Level 1: The entire 220 and 132 kV transmission system is supervised from the National

Control Centre (NCC). At 220/132 kV, 220/66 kV and 132/66kV substations the NCC also

controls the 66kV bus bar voltage. In the case of SCADA system disturbances, the 220kV and

132kV substations can also be controlled from the RCCs. The NCC located at Juja road in

Nairobi is responsible for operation of the Kenyan power system as a whole. Specifically it is

responsible for:

• Long, medium and short term planning of the future operation of the power system

• Proper function and administration of the power system

• Control and monitoring of the entire transmission and distribution networks

• Voltage control in the 220kV, 132kV network and the voltages at the in-feed points to the

66kV and 33kV networks (bus voltages)

• Security analysis of the overall network and applying control actions that achieve the

goal of the system security and economy


• Supervision and monitoring of system and frequency and initiating corrective measures

as necessary

• Determination of spinning reserve for large and medium size power system

• Monitoring the 132kV DC tie line and control of the power purchase from Uganda

• Analysis of outages affecting the power system and equipment

• Preparation of system operation statistics

3.1.2 Level 2: Regional Control Centers

Presently four regional control centers from the second level of dispatching are sub-ordinated to

the NCC. The transmission and distribution networks starting from 66kV down to 11kV is

monitored and controlled by the respective RCCs. They are responsible for:

• The controlling and monitoring of the 66kV and 33kV substations forming the

interconnection points of the transmission network to the distribution system

• Regulation of 11kV voltage in the 66kV and 33kV substations

• Load management on the 66kV, 33kV and 11kV distribution networks

• Co-ordination of switching operations with big industrial plants owning the feeding

substations

3.1.3 Level 3: in the hierarchical structure are the load substation (KenGen or IPPs) but

important information are acquired by the network control centers.

3.2 Existing operational facilities

The facilities for operation of the network of the network at these 3 levels consisting consist of:

• The National Control Center

• Four regional control centers (RCCs) and

• The control and monitoring equipment at the substation

Figure 3.1 shows the levels in the operational hierarchical and the existing control centers with

their interconnections.


Figure 3.1 Existing Hierarchical Structure of Dispatching

3.2.1 Nairobi Control Centre

The control centre comprises a fully redundant control system with servers and front-ends, data

warehouse, training simulator, web server, access from office LAN and six workstations in there

different locations in WAN/LAN connection.

The various applications are accessed via six operator consoles and are run on redundant servers

to ensure reliability. These applications can be tuned for real-time control and analysis as well as

for optimization and planning purposes.

The Network Manager platform uses a web-based full-graphics interface, a real-time relational

database and a modern process communication system to provide uninterruptible real-time

communications with field equipment.

NAIROBI RCC/NCC

COASTAL RCC

MT. KENYA RCC

WESTERN RCC

Transmission S/S

Distribution S/S


Network Manager is based on the industrial IT architecture which facilitates the integration of

systems supplied. It is an open architecture but also allows for maintaining the IT security levels

required by such critical systems.

The figure 3.2 overleaf shows the implementation specification of the National Control Center.

The NCC is located in Nairobi next to the 132/66/11kV substation at Juja road. The SCADA

system was manufactured and commissioned by ASEA in 1990. The system configuration

consists of two process computers Modcomp classic 32/87 and two front-end computers 200.

The front-end computers acquire the SCADA data directly from 23 substations in the Nairobi

region which are equipped with collector RTUs. The NCC receives SCADA data from 14

substations through the Kamburu RCC and from the coastal RCC.

In the control center a mimic board is installed which forms, together with 2 operator stations,

the MMI. They are equipped with two color displays, one alphanumeric keyboard, one function

keyboard and a track ball, which are used for real time operation of the network.

3.2.2 Nairobi Regional Centre

The Nairobi RCC is located at a separate building next to the NCC. The control room is

equipped with a mimic board and two operator stations which are directly connected to the main

computer of the NCC.

The operator stations are equipped with two color displays, one alphanumeric keyboard, one

function keyboard and track ball. One hardcopy unit (connected to the operator station) and two

page printers are also available.


Figure 3.2 Implementation specifications for the National Control Center


3.2.3 Mount Kenya Regional Center

The Kamburu RCC is located on the third floor of hydro power plant of Kamburu. The KenGen

operators are supervising the region from two SINDAC operator stations as well as from control

panels from the 132/33 kV substations Kiganjo and Nanyuki. The master station is also located

at Kamburu power station and is connected to the substations with 33 RTUs in the Mt Kenya

region.

3.2.4 Coastal Regional Centre

The coastal RCC is located at the control room of Rabai 220/132 kV substation. The SCADA

system consists of two process computers and two front-end computers. The front-end computers

receive the process data directly from 8 substations equipped with RTUs.

At the control room one operator station with one color display, one alphanumeric keyboard, one

function keyboard and track ball are installed. Two pose printers are also in the station control.

3.2.5 Western Region Regional Center

The master station at the western RCC is connected to 4 substations in the western region of

Kenya where 33 RTUs are installed. These 132/33 kV substations are Musaga, Chemosit,

Eldoret and Kisumu. The data from 220/11 kV substations and Turkwel power station are

transmitted to the RCC through a PLC concentrator. The control and monitoring panels for

220/132/33 kV for Lessos are also installed.


3.3 Typical Control room Layout

Figure 3.3 shows the layout of a typical control room

Figure 3.3 Typical layout of the computer control room


Figure 3.4 Typical utility control centre

Figure 3.4 shows a graphical depiction of a typical control center. A large control center

typically is staffed by several operators. Each operator is often dedicated to a portion of the

system such as transmission, distribution, or generation. The control center is often set up with

separate areas for each of these functions as well.


The horseshoe control room layout is designed so that anyone in the center can see all the

screens. Operators at any of the operator displays should be able to view the entire control

room’s screens without undue difficulty as well.

Similar areas in the system that are being monitored should be situated close together to avoid

unnecessary movement by the operators to see what is going on.

3.4 Planned Electrical System in Kenya

Kenya has an area of 580,400 km2 and a population of around 31.5 million. It shares its borders

with Somalia, Ethiopia, Sudan, Uganda and Tanzania but has a high voltage connection to

Uganda only. A feasibility study jointly initiated by the governments of Kenya and Tanzania and

aimed at importing power from the South African Power Pool recommended another high

voltage connection with Tanzania.

This section of the design report gives a short overview of the power sector in Kenya with the

purpose of identifying the network to be supervised and determining the operational

requirements to be fulfilled by the SCADA system. The review of the existing power system

analyses the:

• Past, present and expected future power and energy demand in the country,

• Sources of electric power generation in Kenya and the import and export of energy, and

• The existing and planned transmission and distribution networks and facilities in order to

assess the importance of a secure energy supply and the necessity of power application and

energy management functions for the transmission system.


3.5 Present Power Demand

The Kenya Power System has a peak power demand of around 1070MW and energy sales of

around 3,500 GWh. The maximum demand increased only slightly by 7 MW (around 1 %) from

1997/98 to 2000/01 but maximum demand growth picked – up in 2001/02 when it reached 3.9%.

The maximum demand [MW] for the individual areas for the period from 1996/97 to 2001/02 is

shown in figure 3.4 and the respective table.

The main reason for the decrease in power demand and energy sales in the period 1999 to 2001

was a severe drought that forced KPLC to implement an energy rationing plan. With resumption

of normal rainfall in 2001/02 hydro generation was back to normal levels and the rationing plan

was done away with. The situation was further improved with commissioning of additional

generation capacity by independent power producers.

3.5.1 Consumer categories

The total number of consumers has increased steadily over the past years. This comes to no

surprise as it is dominated by the domestic customers whose number has increased from 288,250

in 1996/97 to 430,580 in 2001/02. The number of medium and large commercial and industrial

consumers on the other hand shows a mixed picture with the number of customers in some

categories even decreasing over the same period.

Electricity sales in GWh for the same period split into different consumer categories. Other than

for the number of consumers, the electricity sales to the different consumer categories show

similar pattern with increasing figures from 1996/97 to 1997/98 and a decrease in energy sales in

the 2 following years. The rationing of electricity between 1999 and 2002 affected all consumer

categories.


Figure 3.5 Graph of the Area Maximum Demand (MW)

Area Maximum Demand (MW)

Year 1996/97 1997/98 1998/99 1999/00 2000/01 2001/02

Nairobi Area 372 399 400 408 401 385

Coastal Area 146 141 134 147 140 158

Central Rift 45 45 52 51 50 0

West Kenya 72 77 79 77 75 158

Mt. Kenya 40 44 45 43 47 76

North Rift 35 35 33 31 35 0

Total System 710 741 743 757 748 777

Table 1. Tabulated data of the Area Maximum Demand


3.6 Load Forecast

LF, Load Forecast is a tool for predicting the total system electrical load with a variable time

resolution.

LF is used in both production and transmission utilities for planning purposes. The forecast is

presented both in the form of curves, according to the figure 3.5 and in tabular form. An accurate

LF function is a prerequisite for an optimal production planning procedure. The load forecast for

the next 15 years derives from the recommended generation and transmission expansion program

for Kenya. The table only indicates the additional generation and the transmission lines required

to connect the new power stations to the network. It does, however, not show the additional

transmission lines and substations (or substation extensions) within the transmission and sub-

transmission networks required to transfer the additional power to the consumers.

According to this load forecast, the peak load in Kenya will increase from 829 MW in 2004 to

2184 MW in 2019.


Figure 3.6 Graph of Load Forecast and Generation Expansion


Table 2 Tabulated data of Load Forecast and Generation Expansion

Year Peak Load [MW]

Effective Generation [MW]

Load Growth [%]

2004 829 1102 5.3

2005 873 1103 5.3

2006 926 1139 6.1

2007 983 1239 6.2

2008 1043 1289 6.1

2009 1116 1349 7.0

2010 1195 1504 7.1

2011 1280 1564 7.1

2012 1370 1664 7.0

2013 1467 1724 7.1

2014 1567 1831 6.8

2015 1667 1951 6.4

2016 1781 2058 6.8

2017 1914 2186 7.5 2018 2048 2326 7.0 2019 2184 2473 6.6


3.6.1 Power Transmission System

The Kenyan power transmission system is sub-divided into four Regions:

• The Nairobi Region covers the electrical network of the capital of Kenya and its surroundings

representing approximately 50% of the total load of Kenya. The HV network consists of

220 kV and 132 kV transmission lines and substations feeding, via a meshed 66 kV sub-

transmission system, the 11 kV distribution network.

• The Western Region represents approximately 20% of the total load in Kenya and the HV

transmission network mainly consists of 220/132 kV transmission lines and substations

feeding the 33 kV and 11 kV sub-transmission and distribution networks.

• The Mt Kenya region represents approx. 10% of Kenya’s total load and has a 132kV network

feeding the consumers via 33kV and 11kV distribution networks.

• The Coastal Regional represents approximately 20% of the total load. The HV 220 kV and

132 kV transmission network feeds the 33 kV and 11 kV distribution systems.

The above HV networks are interconnected into a single 220 kV and 132 kV transmission grid

which is in turn interconnected to Uganda grid at Tororo by a 132 kV double circuit line from

Lessos via Musaga.


CHAPTER 4

DESIGN SPECIFICATIONS AND RESULTS

The case study for the SCADA system was undertaken on the Kenya National Grid which is

shown in figure 4.1.

Figure 4.1 The Kenya National Power Grid


4.1 Data Acquisition

The functions to be performed by the SCADA system are described in detail in this section.

Real time data is collected from the following sources for use by the SCADA system.

v Contractor supplied RTUs

23 existing RTUs communicate with the SCADA system through dedicated data channels. They

have single and double pole status, analog and pulse accumulator inputs as well as supervisory

control outputs for switching of circuit breakers and isolators as well as raise/lower controls for

tap changing transformers.

v Contractor Supplied local RTUs

1 new contractor supplied local RTU and 1 re-used RTU at the NCC are located at the

computer room for training, maintenance and testing purposes. Spare RTUs are provided and

installed with simulation tools to simulate process inputs and outputs.

v Calculated data

These are generated by programs that periodically calculate database values. The calculated data

may be generated by programs that are part of the data acquisition function or other application

functions. It may be analog or discrete in nature

v Non-telemetered data entered by operator

These data may be analog or discrete in nature and are similar in all aspects to data collected

from RTUs.


4.1.1 RTU data

Any RTU data may collect data from more than one substation or a substation may have more

than one RTU. All alarm and events messages generated by the SCADA system provide the

name of the substation and bay from which the data originated.

Periodic scans: it is possible to assign each telemetered point to one or more scan groups. Data is

collected from the RTU by specifying the scan group.

Demand scans: the SCADA system is able to collect any and all status and analog values from

any RTU on a non-periodic basic.

Calibration, maintenance and test: the operator is able to declare any RTU in the test mode for

purposes of calibration, maintenance or testing.

Telemetry failure and delete from scan: if valid data are not received from an RTU in response to

a scan command, another scan request for data from that source is issued

4.1.2 Data Processing

The SCADA system prepares all data it acquires for use by the display, control and application

functions.

Analog data: each analog point scanned by the SCADA system is connected to engineering units

before being stored in the database.

Quality markers: the system provides for a number of quality markers with each item of

measurement data.

Zero range: the system provides for the specification of an adjustable zero range for each item of

measurement data.

Data validity tests: data validity tests are performed every five minutes and on demand. It

generates an alarm when the data changes from valid to invalid.


MVA and current calculations: MVA values are calculated for designated transformers or other

equipment. Current calculations are carried out for each end of designated lines, for transformers

and for other devices.

Alarming: For every changed status the system determines if an acknowledgment is required

from a user and, if so, it leads the user through appropriate sequence of menus and pictures to the

point at which the acknowledgment can be made. For a switch status change the system shall

proceed as follows:

• Un-commanded changes in switching state, changes in tele-metered and calculated

discrete points are alarmed. The alarm message includes:

ü Time of detection

ü Station name

ü Point name

ü Description of the field action that took place

ü Current state name

4.2 Topology Processor

The network topology processor analyzes the open/closed status of network switching devices,

such as breakers, and disconnections in order to define the configuration of the grid network for

display and the projection screen. Invalid data is indicated with a question mark. User entered

data is handled as valid information. The configuration is re-evaluated and updated after an

adjustable time delay following a change-of-state of a switching device and is also executed on

demand.

4.3 Data dissemination

The SCADA system provides the ability to transmit and receive data to and from control centers

and other computer systems e.g. metering data processing, settlement system etc. regardless of

the source of the source of the data, the frequency of its collection, or the means used to store it

in database.


4.4 Supervisory Control

The operator is able to control the operation of switching devices connected to the RTUs. The

switching devices that can be controlled from any particular console are determined by the

partitions assigned to that console.

Security: the system provides a comprehensive range of mechanisms designed to prevent or

minimize the risk of damage to personnel and network equipment.

Single controls: the operator is able to select and operate any controllable switching device.

Control sequences: the system offers functions for optimization of complex switching operations

such as feeders, step-by-step dialog, where the all necessary single control operations are

initiated automatically by the system.

4.5 Information storage and retrieval

Data is collected and stored periodically and in response to power system disturbances. The data

consists of accumulator, analog and status point values that are manually entered tele-metered

and calculated together with their associated quality codes.

Journaling: it is provided to capture SCADA system data in to a journal file for later retrieval.

Data from the previous two years is stored and available online.

Archive manager and storage: the SCADA system includes an archive manager to manage the

storage and retrieval of data residing in both online and offline storage.

4.6 Man Machine Interface (MMI)

The principle interface between the user and the SCADA system is the consoles. A mechanism

for defining and controlling user access to the SCADA system at each console is provided. It has

a default mode which enables predefined access from each console. A password security feature

is provided that permits only authorized users to access it.


4.7 Alarms and events

All alarms and events are presented to the operator in a consistent manner and are recorded in the

form of a message. The message is a single line of unabbreviated text that describes the

appearance:

ü Every alarm is displayed in graphical symbol, and has an audible annunciation

and is recorded as a message

ü Group alarms are displayed as a graphical symbol, but do not need extra audible

annunciation and documentation

ü Every event is recorded in a text message

4.7.1 Alarm Presentation

An intelligent alarm system guides the operator using a top-down hierarchy of signaling to the

most important starting place of the disturbance. A basic signaling window is presented on every

screen during real time operation. It is not possible to be removed from the screen.

Basic Signaling window

A basic signaling window is presented on every screen during real time operation. It is not

possible to be removed from the screen. The basic signaling display is configurable and in

general contains only a small number of buttons to select the following functions or displays:

• Power system overview displays

• SCADA system configuration display

• Network overview diagrams.

If the basic signaling display is totally or partially covered by another window, an alarm appears

(e.g. a button starts flashing) then, the basic signaling display is put at the front automatically

The flashing buttons indicate the affected areas. Starting at this point, the operator is guided to

the displays containing detailed information about the alarms.


The figure 4.2 shows the layout of the Basic signaling window

aaaaaaaaaaaaaaabbbbbbbbbbbbbbbbbccccccccccccccccccccdddddddddddeeeeeeeeeeeeeeeeeeefffffffffffffffffffffffffffffeeeeeeeeeeeeeeeeeeeeeeegggggggg

NNNN

NNNN

BBB NNNN

AAA

NNNN

Station AAA

Station nnnStation nnnStation BBBStation nnn

TR xxOFF

ARS

AAA

220 110 XXXoverv

220 110 XXXoverv

220 110 XXXoverv

220 110 XXXoverv

Basic Signaling Window

Window of anyapplication program

Single LineDiagram StationAAAAlarm Overview

220 kV Grid

132132

132 132

Figure 4.2 Basic signaling window

4.7.2 Audible alarm

An audible alarm with two distinct tones is provided for each console. The alarm type defines

selection of an audible alarm sound. The audible alarm device sounds for only a limited period of

time i.e. 1 to 2 seconds or in a single sound e.g. gongs when an alarm is raised. It is able to

disable the audible alarm function at a console and silencing then remains in effect until the

operator restores the audible alarm function.


4.7.3 Alarm inhibit/enable

Inhibiting alarms for a value or device causes all alarm processing of that value or device

continues and the database is updated. Alarm inhibiting causes the SCADA system to:

• Cease all further alarm annunciation for the value or device including symbol flashing

or highlighting

• Present a quality code next to the value or device on every display and hardcopy

containing the item in alarm.

4.8 Displays

It is possible to present any item in the database on any display. All supervisory control and data

control capabilities are supported from any window of a world co-ordinate space. Revise status

are displayed using combinations of symbols, control, descriptions and blinking.

4.8.1 Display features

Each display includes a heading at the top of the display consisting of a title showing, the

unabbreviated name of the display. When a display is larger than the screen being viewed, a

navigator window appears with the display. Movement, using the mouse, of this indicator in the

navigation window causes a corresponding change in the content of the window currently in use.

The engineer has the right to review the format and content of all displays supplied by the

contractor. The engineer has the approval rights for the displays developed by the operator.

The system comprises a graphical data engineering tool which makes it possible to define

objects, topology and pictures in a single straightforward operation. Topology is defined by

simply connecting the graphical symbols representing electrical objects with each other-drawing

it the way it looks.

It is possible to automatically generate pictures from the graphical representation in the data

engineering tool without the need for a separate tool. This is particularly useful when upgrading

the system from an existing database.


RESULTS

On running the system in the presence of the operators the following displays appeared.

Figure 4.3 Dandora substation display


Figure 4.4 Embakasi substation display


Figure 4.5 Juja road substation display


Figure 4.6 Kiambere substation display


CHAPTER 5

TROUBLE SHOOTING AND CONCLUSION

5.0 INTRODUCTION

This section reviews certain methodologies that may be followed for effective troubleshooting

and maintenance of a telemetry system from the digital or analog field input/output at the RTUs

to the computer facilities at the central site. The emphasis in this section is on the methodology

to be used. Basic troubleshooting of the various components of a telemetry system are covered

her. This includes:

v The RTUs and components modules

v Associated equipment interfaced to the RTUs (such as PLCs)

v Master station

v Central site computer facilities

5.1 TROUBLESHOOTING THE TELEMETRY SYSTEM

Ensure that components are not removed on line whilst the system is powered up unless the

manufacturer specifically indicates that this is permissible. Damage to components and modules

can occur when removing whilst the system is still powered up.

5.1.1 RTUs and Component Modules

A typical procedure to follow when reviewing the operation of the telemetry system for faults is:

• Confirm that the power supply module is healthy

• If the power supply is not operating, check that there is power to the power supply

module

• Check the CPU module that the run or healthy light is on

• Check earthing connections for low resistance to earth or whether some other device

hardware has been added to the system

• If CPU module will not run, check the configurations program to see whether that is

faulty or not

• Cycle power to the RTUs before the new program is loaded


• Replace CPU and retry the test

5.1.2 Master Sites

The master site will generally consist of a more complete telemetry unit and higher quality radio

equipment. Appropriate checks include:

• Check that the links to the central site are operating correctly

• Check that the BER alarm light is not on

• Check transmit power

• Check receiver sensitivity

• Check antenna alignment

• Check that connectors are secure and the cable or waveguide has not been damaged

• Check BER tests on each channel

5.1.3 The Central Site

The areas in which to troubleshoot problems here are quite varied as the master station consists

of:

• The operator stations

• The software for the system

• The communications network for the operator stations

5.2 CONCLUSION

The introduction of monitoring and control systems into the infrastructure of the power network

at the Kenya national grid has changed the outdated manual and analogue collection and

recording methods of electrical quantities to an automated digital system leading to better

supervision of the network, improving services level, helping in preparing and analyzing future

developments, better management of electrical resources……etc.

This material has provided an elaborate insight into the state-of-the-art of the technology of the

complete Kenya power system control field. Thus various parts in the Kenya national grid have


been described following different topics stated in the table of contents. The overall system

aspect has, however, been the main issue throughout all this material.

The figures, illustrate in a general manner different control rooms, control room equipment and

the Kenya national grid thus presenting valuable information.

5.3 RECOMMENDATIONS

Certain vulnerabilities exist in most SCADA systems. They are:

v A cyber attack will most likely take one or two primary forms. The first is a direct (low-

level) attack on the end effective hardware – RTU, PLU and PLC. This kind of attack

takes advantage of weakness in the communication channel

v The other form of attack would be the subversion of a control system. This would take

place by crossing from the corporate side of a utility’s IT network to the SCADA control

center

5.3.1 Improve Security

• Create and follow a regularly tested security plan

• Enforce accountability for machines and people

• Digitally sign records to ensure they are not altered

• Secure open communication lines

• Force separation of duties, devices and networks so that no one person can have control

of your network

• Use firewalls both internally and externally


5.3.2 Have a plan

• Decide who is in-charge of security

• Decide what the threat model and threat level are; budget accordingly

• Protect what you can, insure the rest

• Audit regularly to ensure your plan is carried out

5.3.3 Improve security, Enforce Accountability

• Separation of duties- it is important that no one person should have total control of the

network

• The development staff needs to test applications away from the product environment

• Separate portions of the network- the HR department does not need to see into the details

of the product network

• Someone has to ultimately be responsible for what happens on various parts of the

network

5.3.4 Rewards of Improved Security

• Reduction in waste, fraud, and abuse

• Reduction in overall risk to network and business

• Reduction in operational down time, by having better management of the network

• Reduced insurance premium for business insurance

• Reduced difficulty in following increasingly stringent compliance requirements


REFERENCES:

1. Cegrell, Torsten, Power System control technology, Prentice –Hall international series in

control engineering, 1945

2. W. D. Stevenson, Elements of power system analysis, Mc Graw Hill, 1982

3. Russell Don, Marion E Council, power system control and protection, Academic Press,

USA, 1978

4. Robert H Miller, Malinowski, Power system operation, 3rd ed. Mc Graw Hill ,1994

5. Baumud M, Industrial electrical power system software, Chapman and Hall, USA, 1994

6. Martick R. K, Transmission lines for digital and communication networks, IEEE Press,

1995

7. Shafter G, User oriented power systems control, IFAC, Beijing, 1986

8. Gao Zhanjun, PAN Zhencun and BIAN Pen, “ Modeling of relay protection and fault

information systems,” Relay, vol.33, pp. 50-53, Feb 2005

9. ZHOU Ming, REN Jianwen and LI Genyin, “ A multi-agent based dispatching operation

instruction system in electrical power systems,” Proceedings of the CSEE, vol. 24 pp. 58-

62, April 2004

Documents

CHAPTER 1 1.0 BACKGROUND TO SCADA - University of Nairobieie.uonbi.ac.ke/sites/default/files/cae/engineering/eie/SCADA... · SCADA is an industrial monitoring measurement and control