DEVELOPING OF SCALABLE SCADA IN VIEW OF ACQUIRING …4.1 OPC Server 23 4.2 Data Acquisition through...

DEVELOPING OF SCALABLE SCADA IN VIEW OF

ACQUIRING MULTI PROTOCOL SMART GRID

DEVICES.

R.M.J. Rathnayake

109249R

Degree of Master of Science

Department of Electrical Engineering

University of Moratuwa

Sri Lanka

October 2013

DEVELOPING OF SCALABLE SCADA IN VIEW OF

ACQUIRING MULTI PROTOCOL SMART GRID

DEVICES.

Rathnayake Mudiyanselage Jaliya Rathnayake

109249R

Dissertation submitted in partial fulfillment of the requirements for the

Degree Master of Science

Supervised by: Dr.K.T.M.Udayanga Hemapala

&

Dr. Narendra de Silva

Department of Electrical Engineering

University of Moratuwa

Sri Lanka

October 2013

ii

ACKNOWLEDGEMENT

First, I pay my sincere gratitude to Dr. K.T.M. UdayangaHemapala& Dr. Narendra De Silva,

who encouraged and guided me to conduct this study and on perpetration of final dissertation.

I extend my sincere gratitude to Dr. J.P. Karunadasa, Head of the Department of Electrical

Engineering and all the lectures and visiting lectures of the Department of Electrical

Engineering for the support extended during the study period.

I would like to take this opportunity to extend my sincere thanks to Mr.

ChandanaSamarasinghe, Deputy General Manager (WPN), Mr. JayanthaSaram, Deputy

General Manager (R&D), Mr. K.A.D. Subhasinghe, Chief Engineer (Planning

&Development -WPN) and all the Office Staff of Planning & Development Section- (WPN)

of Ceylon Electricity Board who gave their co-operation to conduct my investigation work

successfully.

It is a great pleasure to remember the kind co-operation extended by the colleagues in the

post graduate program, friends and specially my wife PrabhaniPalliyaguru& members of my

family who helped me to continue the studies from start to end.

iii

ABSTRACT

Distribution Automation (DA) can be identified as a method of improving system efficiency

& reliability. It enables distribution utilities to monitor and control their distribution assets

from a central location called “Distribution Control Center” However the distribution

licensees operate in Sri Lanka, reluctant to adopt DA in to their system mainly due to higher

capital investment & heavy dependency on foreign technical expertise in this field. With a

careful study, it can be identified that there are considerable number of DA compatible

distribution components were reside in their respective networks without proper utilization of

features which support DA. These devices were brought in to their networks without

considering DA. Therefore implementing a DA solution by utilizing these devices, should

only be done after conducting a careful study. Device communication plays a pivotal role in

DA. Successful DA implementation heavily relies on device communication. As these

devices were added in to networks in adhoc manner, they tend to support many different

communication protocols and create multiprotocol environment which complicates DA

implementation further.

Larger portion of the distribution network of Sri Lanka comprising of over head network and

linking geographically dispersed distribution equipment to a central control center, where

Supervisory Control & Data Acquisition (SCADA) system resides is a cumber some and

expensive task.

This dissertation discusses on developing a scalable SCADA in view of acquiring multi

protocol smart grid devices to support distribution licensees operate in Sri Lanka to develop a

in house DA solution with local expertise & with minimum capital cost. Further it discuss of

adopting a cost effective communication media to maintain minimum operational cost for the

DA solution.

Western province north (WPN) of Distribution division-2 of Ceylon Electricity Board (CEB)

considered for the study & outcome of the study has been utilized to develop a Distribution

control center in WPN.

iv

TABLE OF CONTENTS

Declaration of the candidate & Supervisor i

Acknowledgements ii

Abstract iii

Table of content iv

List of Figures vii

List of Tables viii

List of Appendices ix

1. Introduction 1

1.1 Background 1

1.2 Importance of Scalable SCADA 1

1.3 Identification of the Problem 2

1.4 Motivation 3

1.5 Objective of the Study 3

1.6 Methodology 3

2. Smart Grid Devices in the Network 5

2.1 Device Categories 5

2.2 Interoperability & open standards 6

2.3 Communication protocols available in smart grid devices 6

2.3.1 DNP3 7

2.3.2 IEC 870-5-101 / 103/ 104 8

2.3.3 Modbus 9

3. Communication Media Selection 10

3.1 Possible Options 10

3.2 Limitations 16

3.3 Data over Cellular Networks 16

3.4 System Architecture &Hardware device Selection 17

3.4.1 Experiment-Stage-1(Serial data communication through

direct wired connection) 17

v

3.4.2 Experiment-Stage-2(Serial data communication through

TCP connection over GPRS.) 18

3.5 Resolving Dynamic IP Issue 20

3.5.1 Solution 1: Public Static IP Address 21

3.5.2 Solution 2: Dynamic Domain Name System(DDNS) 21

3.5.3 Solution 3: VPN Service Provided by Cellular

Serviceprovider 22

4. Multiprotocol Device Integration 23

4.1 OPC Server 23

4.2 Data Acquisition through Matlab- OPC Toolbox 24

4.3 Multi-protocol Device Integration 26

5. Selection of Software Package to Develop a SCADA 28

5.1 Selection Criteria 28

5.2 Scalability 29

5.3 Supported operating systems 29

5.4 Software architecture 30

5.5 Rapid graphics development 30

5.6 Geographical data representation 30

5.7 Alarm handling & reporting 30

5.8 Trending & data logging 31

5.9 Security 31

5.10 Price 31

5.11 Software package selection 31

6. Financial Feasibility 33

6.1 Project Cost Estimation 33

6.1.1 Capital Cost 33

6.1.2 Operation & maintenance cost 34

6.2 Benefits due to distribution automation 35

6.2.1 Reduction in outage duration 35

6.2.1 Reduction in manpower due to reduction in crew

travel time 38

vi

6.3 Cost Benefit Analysis 38

7. Equipment Identification & Graphics Screen Development 40

7.1 Equipment Numbering Scheme 40

7.1.1 MV line numbering scheme 40

7.1.2 MV switchgear numbering scheme 42

7.2 Graphics Screen Development 43

7.2.1 Color scheme & symbol definition 43

7.2.2 Graphics screen development in Iconics Genisis64 43

8. Data Logging, Trending, Analyzing& Alarm Generation 47

8.1 Data Logging 47

8.2 Data Trending 48

8.3 Alarm Configuration 50

8.3.1 AlarmWorX 64 Server 50

8.3.2 AlarmWorX 64 Viewer 51

8.3.3 AlarmWorX 64 Logger 51

9. Project Implementation 53

9.1 Project Overview 54

9.2 Project Schedule 55

9.3 Equipment Installation 57

10. Conclusion and Recommendation 63

Reference List 65

Appendix A: List of Smart grid device in WPN 66

Appendix B: DNP3quick reference List 67

Appendix C: Technical Data sheet of Serial Device Serever 72

Appendix D:WPN SCADA single line diagram 75

Appendix E:Iconics Genisis64 product brochure 76

Appendix F:Cash flow of Control Center establishment work-WPN 82

Appendix G:Feeder loading prior to temporary faults- 2012 83

Appendix H:Feeder restoration duration after temporary faults- 2012 83

vii

Appendix I:Feeder loading prior to temporary faults- 2011 84

Appendix J:Feeder restoration duration after temporary faults- 2011 84

Appendix K:Feeder loading prior to temporary faults- 2010 85

Appendix L:Feeder restoration duration after temporary faults- 2010 85

Appendix M:WPN financial data-2012 86

Appendix N:Project schedule- Establishment of WPN control center 88

LIST OF FIGURES Page

Figure 2.1 Device type share of smart grid devices. 5

Figure 2.2 Protocol share of smart grid devices. 7

Figure 3.1 The serial link is replaced by a TCP connection over GPRS 17

Figure 3.2 Direct serial connection of Auto re-closure control cubicle with WSOS.

18

Figure 3.3 Auto re-closure serial connection setting through WSOS. 18

Figure 3.4 Wired serial connection replaced with a TCP connection over GPRS

19

Figure 3.5 TCP2COM software created virtual serial ports to forward incoming TCP

19

Figure 4.1 IO Server OPC server used to communicate with Noja Power

auto re-closure.

24

Figure 4.2 System configuration to read Auto re-closures data through OPC Toolbox™.

24

Figure 4.3 OPC configuration in OPC Toolbox™. 25

Figure 4.4 OPC read block configuration & Graphical Representation of

OPC data read through OPC Toolbox™

25

Figure 4.5 Schematic of multi protocol device integration over cellular networks

26

Figure 4.6 Auto re-closers in Ekala gantry connected to Matlab through TCP over GPRS.

27

Figure 6.1 MV feeder failure data for year 2010,2011,2012 35

Figure 6.2 Protection zones in a typical 33 kV radial distribution feeder. 37

Figure 7.1 MV Line segment of Feeder 01 –Wattala PSS. 41

Figure 7.2 GraphWorX 64 application interface. 44

Figure 7.3 Templates in the Layout Tab of the GraphWorX64 Ribbon 45

Figure 7.4 SCADA Main Screen 45

Figure 7.5 Display screen for 33 kV Gantry 46

viii

Figure 7.6 Display screen for Auto Re-closure Operation 46

Figure 8.1 TrendWorX 64 Logger 47

Figure 8.2 TrendWorX64 Logger Database Group - Database Connection Tab

48

Figure 8.3 TrendWorX64 Viewer Properties 49 Figure 8.4 Display screen for plotting historical feeder loading 49 Figure 8.5 AlarmWorX64 Server configuration 50 Figure 8.6 Display screen to display Real time Alarms. 51

Figure 8.7 AlarmWorX64 Logger Configuration. 52

Figure 9.1 Functional interrelationship of various units in WPN Control

center.

53

Figure 9.2 Statistical data of Western province north. (Source Medium Voltage plan 2011)

55

Figure 9.3 Single line diagram of display screens. 58

Figure 9.4 Operator Consol. 58 Figure 9.5 120 inch video wall installation. 59

Figure 9.6 120 inch video wall in operation. 59

Figure 9.7 Ekala Gantry (Four Section Double bus bar) 60 Figure 9.8 Auto re-closure automation works- Ganemulla Gantry 60

Figure 9.9 Auto re-closures automation works- Minuwangoda Gantry. 61

Figure 9.10 Auto re-closure automation works- Ragama Rd. Kadawatha. 61 Figure 9.11 Real time status monitoring of auto re-closure located at Ragama

Rd. Kadawatha. 62

LIST OF TABLES Page

Table 3.1 Twisted-Pair Advantages/Disadvantages 10

Table 3.2 Coaxial cable Advantages/Disadvantages 11

Table 3.3 Fiber optic cable Advantages/Disadvantages 12

Table 3.4 Satellite communication Advantages/Disadvantages 12

Table 3.5 Leased Telephone Lines Advantages/Disadvantages 13

Table 3.6 VHF radio Advantages/Disadvantages 14

Table 3.7 UHF radio Advantages/Disadvantages 14

Table 3.8 Microwave radio Advantages/Disadvantages 15

Table 3.9 Cellular communication Advantages/Disadvantages 15

ix

Table 5.1 SCADA software price comparison table. 31

Table 5.2 SCADA software feature comparison table. 32

Table 5.3 SCADA software point comparison table. 32

Table 6.1 Capital cost estimation for WPN control center. 33

Table 6.2 GSS Feeder failure data / 2010, 2011, 2012 36

Table 6.3 GSS Feeder failure data (EF & OC with outage duration less than 20 min)

36

Table 9.1 Power Demand and Energy Sales Data- 2010 54

Table 9.2 HT Lines Length (route length) (According to the progress report April 2010)

55

LIST OF APPENDICIES Page

Appendix A List of Smart grid device in WPN 66

Appendix B DNP3quick reference List 67

Appendix C Technical Datasheet of Serial Device Server 72

Appendix D WPN SCADA single line diagram 75

Appendix E IconicsGenisis64 product brochure 76

Appendix F Cash flow of Control Center establishment work-WPN 82

Appendix G Feeder loading prior to temporary faults- 2012 83

Appendix H Feeder restoration duration after temporary faults- 2012 83

Appendix I Feeder loading prior to temporary faults- 2011 84

Appendix J Feeder restoration duration after temporary faults- 2011 84

Appendix K Feeder loading prior to temporary faults- 2010 85

Appendix L Feeder restoration duration after temporary faults- 2010 85

Appendix M WPN financial data-2012 86

Appendix N Project schedule- Establishment of WPN control center 88

1

Chapter 1

INTRODUCTION 1.1 Background

Electric power utilities have strived to run their businesses as efficient enterprises

providing energy at an acceptable level of quality. Quality of the supply can be

enhanced by introducing distribution automation in to traditional distribution

networks. Distribution Automation (DA) refers to a system that enables an

electric utility to remotely monitor, coordinate, and operate distribution

components in a real-time mode. In a DA system, there are feeder automation

options that include: demand side management (DSM), remote switch control,

integrated voltage control, service restoration, feeder configuration, trouble call,

fault location/isolation, load and safety checks [1].

Supervisory control and data acquisition (SCADA) works as the human machine

interface (HMI) of distribution automation system. It provides status of the

distribution network concerned and generates alarms and trends based on real

time information. It works as an information translator between operator and

field installed smart grid devices [2],[3].

1.2 Importance of Scalable SCADA

Supervisory control and data acquisition (SCADA) system is the key element of DA,

which enable its’ users to monitor and control the devices that are linked with it.

Distribution equipment which supports DA communicates in different protocols and

these devices are scattered in a large geographical area. Investing on a fully fledge

SCADA is not so economical for a small scale distribution utility. Scalable SCADA

solution will enable small scale distribution utilities to enter in to distribution

automation with lesser capital investment by connecting existing DA compatible

equipment to SCADA. Further it will support expansion of the DA solution by

absorbing DA compatible equipment which may add in future.

2

Developing of scalable SCADA in view of acquiring multi-protocol smart grid

devices will bring in a solution for a smaller distribution utility.

Features of the solution

• Scalable

• Support Multiprotocol devices

• Lower level of operation cost

• Lower level of technical expertise requirement

• Improve local engineering skills

1.3 Identification of the Problem

There are five power distribution licensees operating in Sri Lanka. All of them have

smart grid devices in their respective networks, such as load breaks switches, Auto

re-closures, digital energy meters, electronic protection relays etc. Distribution

licensees invest considerable amount of money on these smart devices. However

proper utilization of “Smarter capabilities” in these devices are rare.

Role played by the power utility regulator will further pressurize distribution utilities

in view of increasing network reliability. Regarding network reliability, regulator

may move on to penalty based schemes which may create unfavorable situation for

distribution licensees, who will go with traditional network operating strategy.

Formulating a Distribution automation scheme with existing recourses will save cost

and time for the licensee. Lower initial capital investment must be support with a

lower level of operating cost. Communication infrastructure contribution to the

operation cost is significant and selecting a cost effective communication media is

essential.

Problem can be formulated as follows.

“Scalable SCADA need to be developed in view of acquiring multi-protocol smart

grid devices together with a cost effective communication infrastructure.”

3

1.4 Motivation The outcome of this project will be to develop a scalable SCADA system for Ceylon

Electricity Board- Western province north (WPN). This will enhance control center

operation and will increase network reliability level of WPN.

Western province north itself contributing to one fifth of the total revenue earn by

CEB. Increase in network efficiencies will benefit both the utility and its consumers.

Positive effect on customers will improve the wellbeing of the people and the

economy of the country.

1.5 Objective of the Study Developing of a scalable SCADA system in view of acquiring multi-protocol smart

grid devices together with a cost effective communication media and implement the

solution in Western Province North of Ceylon Electricity Board.

1.6 Methodology

1. Identification of smart grid devices located in medium voltage network and study

communication protocols operating in those devices.

2. Study about available communication media that can be used for the project and

selecting a best communication media.

3. Identification of suitable software package among several software packages to

develop scalable SCADA.

4. Resolving multi-protocol device communication issue.

5. Initiating a pilot project to investigate pros and cons of the proposed system.

6. Conducting a cost benefit analysis to check financial feasibility of implementing

scalable SCADA.

This study will help to find a feasible solution for the problem mentioned in section

1.3 and the results obtained through this study could be used to implement

distribution automation in other distribution utilities.

2

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2.2 Interoperability and open standards

Historically, SCADA system communication protocols have been developed as

proprietary protocols, each created by a manufacturer as part of a proprietary system,

to meet the specific needs of a particular industry. However, proprietary protocols

have disadvantages for the user. As a system is developed over time the owner is

either locked in to expansion using the same proprietary system, or is compelled to

replace substantial parts of the system to change to another manufacturer’s protocol.

The key benefit of an open standard is that it enables interoperability between

equipment from different manufacturers [5].

2.3 Communication protocols available in smart grid devices

A communication protocol is a system of digital rules for message exchange within

or between computers or any other intelligent hardware. Communicating systems use

well-defined formats for exchanging messages. Each message has an exact meaning

intended to provoke a particular response of the receiver.

After conducting a site survey it was found that following open communication

protocols are in cooperated in most of the smart grid devices. Some devices support

multiple numbers of protocols.

a. DNP3

b. IEC 870-5-101 and 104

c. IEC 870-5-103

d. Modbus

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• Breaks messages into multiple frames to provide optimum error control and

rapid communication sequences

• Allows peer–peer topology as well as master–slave

• Allows multiple master topology

• Provides user definable objects

• Provides for reporting by exception/event without polling by master

• Provides for ‘changed data’ only responses

• Broadcast messages

• Secure configuration/file transfers

• Addressing for over 65 000 devices on a single link

• Provides time synchronization and time-stamped events

• Data link and application layer confirmation

2.3.2 IEC 870-5-101, 103, 104

IEC 60870-5 refers to a collection of standards produced by the International Electro

technical Commission, or IEC, to provide an open standard for the transmission of

SCADA telemetry control and information.

IEC 60870-5 provides a detailed functional description for telecontrol equipment and

systems for controlling geographically widespread processes. The standard is

intended for application in the electrical industries, and has data objects that are

specifically intended for such applications; however it is not limited to such

applications as it has data objects that are applicable to general SCADA applications

in any industry. Nevertheless, the IEC 60870-5 protocol is primarily used in the

electrical industries of European countries.

IEC 870-5- 101

IEC 60870-5-101 is a standard for power system monitoring, control and associated

communications for telecontrol, teleprotection, and associated telecommunications

for electric power systems. This is completely compatible with IEC 60870-5-1 to

IEC 60870-5-5 standards and uses standard asynchronous serial telecontrol channel

interface between devices.

8

IEC 870-5- 103

IEC 60870-5-103 is a standard that enables interoperability between protection

equipment and devices of a control system in a substation. The standard supports

some specific protection functions.

IEC 870-5- 104

IEC 60870-5-104 protocol is an extension of IEC 870-5-10 protocol with the changes

in transport, network, link and physical layer services to suit the complete network

access. The standard uses an open TCP/IP interface to network to have connectivity

to the LAN (Local Area Network)

2.3.3 Modbus

Modbus is a serial communications protocol originally published by Modicon (now

Schneider Electric) for use with programmable logic controllers (PLCs). Modbus is

now a commonly available protocol of connecting industrial electronic devices. The

main reasons for the use of Modbus in the industrial environment are:

• Open Protocol

• Simple and easy to implement

9

Chapter 3

COMMUNICATION MEDIA SELECTION

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

transferred between the SCADA software application located in the central server

and the field installed RTUs. The Communication Network refers to the equipment

needed to transfer data to and from different sites. There is several communication

Medias available that fall in to wired and wireless categories [6].

3.1 Possible Options

However following communication Medias were studied in view of understanding

the advantages and limitations they offer when it comes to SCADA communication

[7].

• Twisted pair and Coaxial cables

• Fiber Optics

• UHF/VHF Radio

• Telephone Lease lines

• Microwave and Satellite,

• Cellular (GPRS/3G).

Twisted-Pair Metallic Cable

The cables are essentially the same as those used by the Telephone Company and

contain a number of pairs of conductor. Aerial cables would be more appropriate for

installation in the utility’s service area since the Utility may own a large number of

distribution poles from which the cables could be suspended.

Table 3.1 list advantages and disadvantages of twisted pair cables.

Advantages Disadvantages

‐ Economical for short distances

‐ Subject to breakage

10

‐ No licensing, fewer approvals

‐ Existing pole Infrastructure can

be used

‐ Relatively high channel

capacity (up to 1.54 MHz) for

‐ short distances

‐ Subject to water ingress

‐ Subject to ground potential rise

due to power faults and lightning

‐ Failures may be difficult to

pinpoint

Table 3.1: Twisted-Pair Advantages/Disadvantages

Coaxial Metallic Cable

Coaxial cable is constructed of a center copper conductor, polyvinyl chloride (PVC)

insulation, a braided or extruded copper shield surrounding the center conductor and

PVC insulation, and a plastic jacket cover. Coaxial cable can transmit high frequency

signals up to several MHz with low attenuation compared to twisted pair wires used

for telephone service. They can be installed underground, direct burial, overhead, and

on existing power line structures. Table 3.2 list advantages and disadvantages of

coaxial cables.


‐ Economical for short distances


‐ Existing pole Infrastructure can

be used

‐ Higher channel capacity than

Twisted-Pair cables

‐ More immune to Radio

Frequency (RF) noise interference

than Twisted Pair



‐ Subject to ground potential rise

due to power faults and lightning

‐ Failures may be difficult to

pinpoint

Table 3.2: Coaxial cable Advantages/Disadvantages

11

Fiber Optic Cable

Optical fibers consist of an inner core and cladding of silica glass and a plastic jacket

that physically protects the fiber. Special types of fiber optic cables have been

developed for the power industry. One type of fiber cable is the Optical Power

Ground Wire (OPGW) that is an optical fiber core within the ground or shield wire

suspended above transmission lines. Another type of optical fiber cable is the All-

Dielectric Self-Supporting (ADSS) cable that is a long-span of all dielectric cables

designed to be fastened to high voltage transmission line towers underneath the

power conductors. A Wrapped Optical Cable (WOC) is also available that is usually

wrapped around the phase conductor or existing ground/earth wire of the

transmission or distribution line. Aerial fiber optic cable can be fastened to the

distribution poles under the power lines.

Table 3.3 list advantages and disadvantages of fiber cables.


‐ Immune to electro

magneticinterference

‐ Immune to ground potential rise


‐ Higher channel capacity

‐ High capital cost



‐ Expensive test equipment

Table 3.3: Fiber optic cable Advantages/Disadvantages

Satellites

The satellites are positioned in geo-stationary orbits above the earth’s equator and

thus offer continuous coverage over a particular area of the earth. Satellites contain a

number of radio transponders which receive and retransmit frequencies to ground

stations within its “foot print,” or coverage, on the earth’s surface.

12

Satellites use both the C-band and the Ku-band. Very Small Aperture Terminal

(VSAT) technology has advanced to the point where a much smaller antenna (down

to about one meter) can be used for Ku-band communications. This has resulted in

the Ku-band being preferred for sites with modest communications requirements.

VSAT technology is advancing steadily, and the capital costs have dropped

substantially. Continual time-of use charges must be considered in the use of satellite

communications.

Table 3.4 list advantages and disadvantages of Satellite communication.


‐ Wide area coverage

‐ Easy Access to remote sites

‐ Costs independent of distance

‐ Low error rates

‐ Adaptable to changing network

patterns

‐ No right-of-way necessary

‐ High equipment cost

‐ Less control over transmission

‐ Transmission time delay

‐ Reduced transmission during

solar

equinox

‐ Continual leasing costs

Table 3.4: Satellite communication Advantages/Disadvantages

Leased Telephone Lines

Leased dedicated lines can be used for dedicated communication requirements, such

as SCADA. Wideband channels may be available for high speed data signaling.

Circuit characteristics can often be conditioned for many other uses, including voice

and various types of low and medium speed data.

Table 3.5 list advantages and disadvantages of leased telephone line.


‐ Lower capital investment

‐ Maintained circuit quality

‐ Repair and maintenance is not

controlled by the lessee

13

‐ Lesser communication expertise


patterns


‐ Lease lines may not be available

at some sites

‐ Require protection against

ground potential rise

‐ Continual leasing costs

Table 3.5: Leased Telephone Lines Advantages/Disadvantages

Very High Frequency Radio

The Very High Frequency (VHF) band extends from 30 to 300 MHz and is usually

used by utilities for mobile radio.

Table 3.6 list advantages and disadvantages of VHF radio.


‐ Not dependent on power lines and

common carriers

‐ Greater field strength coverage

patterns than UHF band


patterns


‐ Low channel capacity

‐ Low digital data bit rate

‐ Limited transmission techniques

available

Table 3.6: VHF radio Advantages/Disadvantages

Ultra High Frequency Radio

The Ultra High Frequency (UHF) band extends from 300 to 3000 MHz. The bands

typically considered for UHF radio are in the 400 MHz and 900 MHz range. Most of

the suitable radio products for SCADA applications available operate in the 900

MHz frequency range

14

Table 3.7 list advantages and disadvantages of UHF radio.


‐ Not dependent on power lines and

common carriers


patterns


‐ Low channel capacity

‐ Low digital data bit rate

‐ Limited transmission techniques

available

Table 3.7: UHF radio Advantages/Disadvantages

Microwave Radio

Microwave radio is a term used to describe UHF radio systems operating at

frequencies above 1 GHz.

Table 3.8 list advantages and disadvantages of Microwave radio.


‐ High Channel Capacityand data

rates


patterns

‐ Independent from power lines

and

common carriers

‐ Line of sight clearance required

‐ Specialized test equipment and

training

‐ Frequency assignments

sometimes

unavailable in urban areas

‐ More expensive site development

Table 3.8: Microwave radio Advantages/Disadvantages

Cellular (GPRS/3G)

In recent years, with the development and progressive implementation of packet

switching technologies over mobile networks (GPRS/UMTS/EDGE), a new range of

possibilities has opened up which may make them viable for SCADA applications.

15

On the one hand, a TCP/IP-based service is offered, which guarantees the reception

of traffic and the “always online” nature of this type of service. Further, charges

based on exchanged traffic volume, as opposed to circuit switching connections

which are charged by connection time, may be a very attractive feature for utilities.

Table 3.9 list advantages and disadvantages of Cellular communication.


‐ No need to consider geographic

condition, easy deployment, save

time and construction costs

‐ Capable in harsh EMC

circumstances

‐ IP based, easy deployment and

remote management, diagnose

and maintenance

‐ Always online to ensure

reliability

‐ Low communication costs

‐ Fast transmission speed

‐ Low consumption Cost


patterns

‐ Independent from power lines and

common carriers

‐ Latency can be considerable,

reaching values from 200 ms per

link (typical for UMTS), 500-700

ms (typical for GPRS) and up to

several seconds (GPRS with low

coverage and a traffic-saturated

network)

‐ Total dependency on a outside

facility

Table 3.9: Cellular communication Advantages/Disadvantages

16

3.2 Limitations

Use of wired communication media 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.

Remote sites are usually not accessible by wired media. The use of wireless media

offers an economical solution. Out of available wireless options, Cellular (GPRS/3G)

communication comes to the top due to wide availability, lower capital investment

and relatively low operational cost.

3.3 Data over Cellular Networks.

There is a certain degree of reluctance among utilities in the electric sector towards

using public communications infrastructures for SCADA applications. This is due to

the existence of a series of factors which used to make this strategy ill-advised, such

as:

Reduced availability and reliability of public communications solutions

compared to utility owned ones

Increased security of using a utility owned communication network which is

completely closed off to the outside world

Autonomy in service provision

Despite above considerations, In CEB, almost all the heavy supply energy

meters were read through GSM data connections obtained from cellular

service providers, Developments in the cellular sector in recent years favor

the use of cellular communications networks. Following factors were

influenced when selecting cellular network for SCADA application.

Public utilities commission applies growing pressure on electric utilities to

reduce operational and maintenance costs.

17

Solution scalability. The number of connections can be increased by

contracting them from the service provider (or contracting another service

provider)

Communication infrastructure is owned and maintained by the operator and

only its use can be contracted.

Improvement in geographic coverage of cellular networks in Sri Lanka. It is

increasing in all areas and an increasing proportion of inhabited territory is

covered

Progressive improvement in communications service quality (3G, 4G, etc.)

3.4 System Architecture and Hardware device Selection

In a typical SCADA application there is a serial connection between Control Center

and a RTU located in a remote installation. In traditional SCADA communication

this serial connection is realized by means of a twisted pair, radio communications

channel and micro wave links or by satellite and telephone networks. In the proposed

solution with GPRS communication, the serial link is replaced by a TCP connection

created over GPRS. See Figure 3.1.

Figure 3.1: The serial link is replaced by a TCP connection over GPRS

18

3.4.1 Experiment- Stage-1

(Serial data communication through direct wired connection.)

For testing serial data communication, direct wired connection was made between an

Auto re-closure control cubicle and a Lap top running WSOS (Windows Switchgear

Operating System) provided by the Auto re-closure supplier. WSOS is used to set

parameters, read measurement and download event data stored in Auto re-closures

[8].

Figure 3.2: Direct serial connection of Auto re-closure control cubicle with WSOS.

19

Figure 3.3: Auto re-closure serial connection setting through WSOS.

Serial data communication over direct wired connection is successful and wired

connection will be replaced during the stage-2 of the experiment.

3.4.2 Experiment- Stage-2

(Serial data communication through TCP connection over GPRS.)

To replace wired serial link by a TCP connection over GPRS, GPRS IP modem has

used.

20

Figure 3.4: Wired serial connection replaced with a TCP connection over GPRS.

Instead of using two IP modems, PC end IP modem was replaced by installing a TCP

to Serial conversion software. Function of the software is to direct incoming TCP

traffic comes through the TCP port (TCP port 10000) to a virtual serial port of the

PC.

Figure 3.5: TCP2COM software created virtual serial ports to forward incoming TCP traffic. Again WSOS (Windows Switchgear Operating System) provided by the Auto re-

closure supplier used to verify the operation of the auto re-closure through a serial

connection created over GPRS cellular network. During the experiment following

observations were made.

‐ It is important to adjust all of the application timeouts in the applications to

the new transmission technology. The link latency increases to the order of

seconds, and it is therefore essential to increase time values accordingly [9].

‐ Cellular service provider, often assign temporary IP addresses to their clients

to access the Internet. Compared with static IP addresses, using dynamic IP

addresses make it difficult for the PC to keep in constant contact with remote

devices. This issue has termed as “dynamic IP issue”and method of resolving

21

this issue discussed in the following section.

3.5 Resolving Dynamic IP Issue

Traditional SCADA systems use a polling architecture that will only work properly if

the SCADA host knows the IP addresses of the field installed RTU. The trouble with

field installed RTU in GPRS environment is that the devices receive a different IP

address every time they connect to the GPRS cellular network. This has termed

“Dynamic IP Issue”. To overcome dynamic IP issue, three distinct solutions have

been considered [10].

3.5.1 Solution 1: Public Static IP Address

The first choice is to get a public static IP address. If Cellular provider can assign a

public static IP address to a specific SIM card, field installed RTU will have their

own static IP address and the entire system will operate in the same manner as a

traditional monitoring system that uses physical wiring. Perhaps the main benefit of

this solution is that it behaves the same as a wired solution. However, none of the

cellular providers operating in Sri Lanka had offered this kind of service, and when

they do the cost will be very high.

3.5.2 Solution 2: Dynamic Domain Name System (DDNS)

The Dynamic Domain Name System (DDNS) is used to convert a device’s name into

a dynamic IP address so that remote devices can communicate with the control center

using a fixed domain name. DDNS is one type of DNS server. The difference

between DDNS and DNS is that DDNS takes care of the Dynamic IP address of a

device, and DNS the static IP address of a device. With most remote GPRS devices,

need to apply for a hostname for each of the devices handled by the DDNS server.

When GPRS devices get an IP from the cellular provider, they will automatically

connect to the GPRS network. Each time a GPRS device’s built-in DDNS client gets

22

a new IP address, it will send the IP address to the DDNS sever. The mapping table

in the DDNS server is refreshed each time the DDNS receives a new IP address from

the devices.

The host can find a device’s IP address from the DDNS’s mapping table by looking

up the device’s hostname. For this solution there are two concerns:

(1) A majority of DDNS servers do not have standard protocols to implement

IP address updates, which makes it difficult for some GPRS devices to obtain

IP address updates from DDNS.

(2) The quality of the service; as DDNS service is usually provided by a third

party service provider, the system may crash when the DDNS loses

connection or is being maintained. In addition, it may be necessary to pay a

premium to the DDNS service provider for better quality of service.

3.5.3 Solution 3: VPN Service Provided by Cellular service provider

A VPN (Virtual Private Network) is a secure LAN solution that groups specific

devices together. VPN has two major functions security and grouping. VPN grouping

concept solves the dynamic IP address issues.

The grouping of the devices into one private network prevents unauthorized persons

from accessing the data. To obtain a VPN solution, utilities need to consult cellular

service providers operated in the concerned area. When the GPRS device dials up,

the cellular service provider will assign a private IP address to it and because the

private IP address is on the same network segment as the SCADA host, devices can

maintain bi-directional communication using a polling architecture.

A VPN solution was obtained from Mobitel Pvt. (Ltd) on trial basis to test the

functionality of the system and results were encouraging.

23

Chapter 4

MULTIPROTOCOL DEVICE INTEGRATION

As discussed in Chapter 2, smart grid devices communicate in dissimilar protocols

and leaving SCADA system to work in a multi-protocol environment. Multi-protocol

environment can be addressed by two means [11].

1. Incorporate protocol device drivers to SCADA system to directly

communicate with field devices through their native protocols.

2. Using industry standard Object linking and embedding for process control

(OPC) protocol to work as a middleware and translate various protocols to a

single protocol called OPC.

4.1 OPC Server

OPC was designed to provide a common bridge for Windows based software

applications and process control hardware. Standards define consistent methods of

accessing field data from plant floor devices. This method remains the same

regardless of the type and source of data. An OPC Server for one hardware device

provides the same methods for an OPC Client to access its data as any and every

other OPC Server for that same and any other hardware device.

IO Server, OPC server software used for the study. It supports more than 20

communication protocols including DNP3 and Modbus. Figure 4.1 shows the

configuration done in IO Server to communicate with Noja Power auto re-closure in

DNP3 protocol with direct wired serial connection.

24

Figure 4.1: IO Server OPC server used to communicate with Noja Power auto re-

closure.

4.2 Data Acquisition through Matlab- OPC Toolbox

OPC Toolbox™ provides a connection to OPC DA and OPC HDA servers.It gives

access to live and historical OPC data directly from MATLAB® and Simulink®. It

enables data read, write, and log OPC data from field installed devices, such as auto

re-closures, supervisory control and data acquisition systems, and programmable

logic controllers, that conform to the OPC Foundation Data Access (DA) standard.

25

Figure 4.2: System configuration to read Auto re-closures data through OPC

Toolbox™.

OPC tool box reside in Matlab Simulink module. By adding an OPC configuration

block to a new Simulink model, OPC client configured to fetch data from an OPC

server such as IOServer to work in Simlink environment.

Figure 4.3: OPC configuration in OPC Toolbox™.

After configuring client to access IOServer OPC server in client manger, OPC read/

write blocks can be used to read and write data to OPC servers.

26

Figure 4.4: OPC read block configuration and Graphical Representation of OPC data

read through OPC Toolbox™

27

4.3 Multi protocol Device Integration.

By using the method described in section 4.2, devices communicate in multiple

protocols can be linked to an application (SCADA) with the help of an OPC server/

servers which supports said protocols. Figure 4.5 shows conceptual schematic of

multi protocol device integration over cellular networks. Results of the experiments

described in section 3.4.2(Serial data communication through TCP connection over

GPRS.) and section 4.2 (Data Acquisition through Matlab- OPC Toolbox) were

combined to develop the multi protocol device integration schematic.

Figure 4.5: Schematic of multi protocol device integration over cellular networks

4.4 Pilot Project- Real time data monitoring of Auto re-closures.

Aim of this pilot project is to initiate communication over GPRS to connect four

Auto re-closures located in Ekala Gantry with Matlab. OPC Toolbox used to extract

data from OPC server.4 nos. GPRS IP modems with static IP SIM cards were

installed in Auto re-closures.

Figure 4.6 shows the feeder currents of each Auto re-closure read by OPC Toolbox.

Role played by OPC tool box will be replaced by a SCADA software package during

the actual project implementation stage.

28

Figure 4.6: Auto re-closers in Ekala gantry connected to Matlab through TCP over

GPRS, Display shows feeder currents in Auto re-closures.

Results confirmed that data over cellular networks (GPRS) can be used in SCADA

applications and using of OPC servers will resolve multiprotocol device

communication issues. By developing a SCADA system using a suitable software

package, information gathered from Auto- re-closures can be displayed graphically

and data can be stored as historical data. Selecting a suitable software package to

develop SCADA system will be discussed under chapter 5.

29

Chapter 5

SELECTION OF SOFTWARE PACKAGE TO DEVELOP A SCADA

Choosing a right software package to develop a SCADA is a challenging task when

it comes to power distribution automation due to following reasons.

• .Operational criticalness

• Maintainability

• Size of the investment

• Higher number of device connectivity

• Security

It was decided to perform ‘hands-on’ evaluation of the short-listed products. The

evaluation process was intended to look at the basic functionality of the products and

to assess their ease of use, both in development as well as during run-time, whilst

look in more depth at a number of specific issues related to using such a system in

Power Distribution Automation environment [12].

Software evaluation concentrated on the basic SCADA features such as the

configuration tools, the Human Machine Interface (HMI), alarm and event handling,

logging and archiving as well as the access control mechanisms. These were

evaluated from both a functional, as well as, from usability point of view criteria

against which the SCADA systems could be evaluated [13].

Following software packages were considered for the evaluation

• Genisis64 of ICONICS

• iFIX of General Electric

• Citect SCADA of Schneider

30

5.1 Selection Criteria

Following key areas were considered during the SCADA software selection process.

• Scalability

• Supported Operating Systems

• Software architecture

• Rapid Graphics development

• Geographical data representation

• Alarm Handling and Reporting

• Trending and data logging

• Security

• Price

Depend upon their relative importance; points were assigned to grade the software

packages. Weighting factors were assigned to each of the feature to calculate total

points gained by a software package.

5.2 Scalability

A Scalable SCADA allows a utility to start with a SCADA system that matches its

size and budget requirements, then grow as the utilities need for units, I/O, and

system intelligence increases. And the expansion is done in a cost-effective manner.

Genisis64 and iFIX software not required to compilation before use. This has been

accomplished by a “save” function. However Schneider Citect SCADA requires

compilation before use and compilation process will not complete until all

compilation errors being corrected. This issue does not allow Citect SCADA to be

used in an environment that needs constant growth in the application.

5.3 Supported Operating Systems

Software used to develop SCADA system must be based on proper computing

platform in order to take leverage the advantages of larger memory capacity (greater

than 4 GB of RAM), hardware acceleration, multi-core processors and multi-

threading. Only ICONICS Genisis64 supports 64 bit operating system and it capable

of operating in computers that has larger in memory capacity.

31

5.4 Software architecture

Software architecture shall be based on a modular architecture (separate stand-alone

modules for Dynamic Graphic Displays, Real-Time Trending and Historical Data

Logging, Alarm Management, Security, GEO-SCADA, Data Management, Real-

time OPC) and be inherently based on a distributed architecture that supports

Microsoft Windows networking as well as OPC-based technology, since OPC being

used to address multi protocol device communication issue.

ICONICS Genisis64 supports modular architecture than other two SCADA

softwareS.

5.5 Rapid graphics development

Medium voltage Power distribution network comprising of many nodes and Software

must support rapid graphics development to create large number of graphics screen

in a shorter period. With ICONICS Genisis64, it is possible to convert existing Auto

cad drawings in to vector graphics and directly use them in the SCADA environment

without re-drawing them. General Electric iFIX and Schneider Citect SCADA do not

support this feature.

5.6 Geographical data representation

Power distribution equipment located in geographically dispersed locations and it is

important to see their data on a geographical map. Selected software need to support

geographical representation and it should enable direct importing of data gathered

through GIS mapping. ICONICS Genisis64 comes with a mapping module called

Earth WorX and it supports import of .gpx file generated by GIS software.

5.7 Alarm handling and reporting

Alarm handling and reporting capabilities of all the software packages are equally

good. Schneider Citect SCADA provides professional grade templates for creating

alarm display screens.

32

5.8 Trending and data logging

Trending and data logging capabilities of all the software packages are equally well.

However ICONICS Genisis64 provides more interactive trending templates than

other two software packages.

5.9 Security

Software package should provide a configurable security component that can be used

to restrict access, application navigation and configuration of databases or displays in

SCADA system. It should also support configuration of different sets (or policies) of

individual users. It should support categorization (grouping) of those users. All of the

above mentioned software support above criteria.

5.10 Price

Pricing of the software package varies with the number of supported tags. Pricing

inquiry was made for software package that supports 15,000 on demand tags with

one development license and three client licenses. Results are as follows.

Software Package Price

ICONICS Genisis64 2,400,000.00

General Electric iFIX SCADA 5,800,000.00

Schneider Citect SCADA 3,800,000.00

Table 5.1 SCADA software price comparison table.

5.11 Software package selection for SCADA

Following marking scheme ware used to grade software packages.

Excellent-5, Very Good-3, Good-2, fine-1

33

Result of the evaluation is shown in Table 5.1. Weighting factor assign to each

feature to calculate total points gained by a software package.

Feature Assign weight ICONICS Genisis64 General Electric iFIX

Schneider Citect SCADA

1 Scalability 15 Excellent 75 Very Good 45 Fine 15

2 Supported Operating Systems 5 Excellent 25 Good 10 Good 10

3 SCADA software architecture 5 Excellent 25 Very Good 15 Very Good 15

4 Rapid graphics development 20 Excellent 100 Good 40 Good 40

5 Geographical data representation 10 Excellent 50 Fine 10 Fine 10

6 Alarm handling and reporting 10 Very Good 30 Very Good 30 Excellent 50

7 Trending and data logging 10 Excellent 50 Very Good 30 Very Good 30

8 Security 10 Very Good 30 Very Good 30 Very Good 30

9 Price 15 Excellent 75 Good 30 Very Good 45

Total 100 460 240 245

Average (Total/500) 0.92 0.48 0.49

Table 5.2 SCADA software feature comparison table.

Software Package Total Points

Earned

Average

ICONICS Genisis64 460 0.92

General Electric iFIX 240 0.48

Schneider Citect SCADA 245 0.49

Table 5.3 SCADA software point comparison table.

From the above table it can be seen that ICONICS Genisis64 shows salient features

than other two software packages. Therefore, ICONICS Genisis64 considered as the

selected software package to develop the SCADA system for the project.

34

Chapter 6

FINANCIAL FEASIBILITY

Grater amount of money needed to be spent as capital expenditure to owing a

SCADA system for a distribution utility. Quantifying benefits obtained through

distribution automation in financial terms are not straight forward. However benefits

obtained due to reduction in outage duration and reduction in crew travel time can be

quantify with reasonable level of accuracy. Therefore those two items were

considered for quantifying potential saving due to distribution automation.

Only the relevant cost and benefits obtained after implementing 1stand 2nd stages of

the project (Chapter 9) considered for the financial feasibility. Other stages need to

analyze case by case basis.

6.1 Project Cost Estimation

6.1.1 Capital cost

Land and building costs were not considered as the SCADA system will be setup in

the existing control center building of CEB- Western province north (WPN) office.

Capital cost estimation is 18 Mn LKR. Details are shown in the table 6.1

No. Item Qty Capital Expenditure

(Rs.)

1 SCADA software (Development and runtime license) 1 2,400,000.00

2 OPC Server Software for SCADA 1 200,000.00

3 600 VA UPS for Control center PCs 6 50,000.00

4 IP based wireless CCTV surveillance cameras 3 60,000.00

5 24 inch LCD display for SCADA 3 90,000.00

35

6 60 inch seamless LCD display for SCADA video

Wall 4 7,000,000.00

7 Low end Server Computer (SCADA development

and server station) 1 250,000.00

8 Multi Monitor Controller for Operator Consol 1 250,000.00

9 Quad Display Computer for video wall 1 400,000.00

10 Desktop PC (SCADA Client station) 2 250,000.00

11 Serial data servers for Auto re-closure and LBS

automation 200 7,000,000.00

Total Capital Investment

17,950,000.00

Table 6.1 Capital cost estimation for WPN control center.

6.1.2 Operation and maintenance (O&M) cost

Control center operations take place around the clock and it is necessary to deploy

additional staff to the control center. There will be additional charges to maintain

communication infrastructure and obtain adequate spares for day to day operations.

O&M cost comprising of following three key components.

a) Wages for staff

b) Cost of communication infrastructure

c) Spare parts cost

Wages for staff

No of employees - 6 nos.

Average salary per month -65,000.00 LKR

Cost per year -4.68 M LKR

36

Cost of communication infrastructure

Subscription fee for VPN - 25,000.00 LKR

No of data SIMs -200 nos.

Average data charge for a SIM -250 LKR

Cost per year -0.625 M LKR

Cost of spare parts

2 % of Capital Expenditure/ Yr -0.36 M LKR

For more details refer Appendix F - Cash flow of Control Center establishment

work-WPN

6.2 Benefits due to Distribution automation.

Following two key areas were considered to quantify the benefit of distribution

automation.

– Reduction in outage Duration

– Reduction in Manpower due to reduction in Crew Travel time

6.2.1 Reduction in outage Duration

To determine reduction in outages, it is important to study feeder existing feeder

tripping details. Figure 6.1 shows feeder failure data recorded in GSS for year 2010,

2011, 2012

37

Figure 6.1: MV feeder failure data for year 2010,2011,2012

There are 74 MV feeders and failures per month per feeder were calculated as

follows.

Year EF OC OC-EF UF Other Total 2010 1609 228 1288 60 95 3280 2011 1816 259 1562 119 104 3860 2012 1599 209 1804 200 34 3846 Avg. per year 1675 232 1551 126 78 3662 Avg. per month 140 19 129 11 6 305 Failure/month/feeder 1.9 0.3 1.7 0.1 0.1 4.1

Table 6.2: GSS Feeder failure data / 2010, 2011, 2012

As can be seen from Table 6.2, there are around 4 failures per month per feeder due

to Earth fault and over current. These tripping were recorded in the Grid substation

breakers. Therefore we can come to a conclusion that there would be more faults in

1609

1816

1599

228 259 209

1288

1562

1804

60119

20095 104

340

200

400

600

800

1000

1200

1400

1600

1800

2000

2010 2011 2012

Failures

per

year

Year

MV Feader Failure- 2010,2011,2012

EF

OC

OC-EF

UF

Other

38

the network which were not detected by the protection schemes installed in grid

substations. Such as faults down steam of auto re-closures and DDLO fuses.

Temporally faults that cause auto re-closure lockout due to higher fault current can

be identified from the feeder tripping data by considering outage duration. Faults

having outage duration less than 20 minutes (Response time 5 min + Crew Travel

time 10 min + Restoration time 5 min) can be considered as such temporally faults.

Table 6.3 gives number of EF and OC tripping with outage duration less than 20 min

with average feeder current just before the tripping of the circuit breaker for year

2010, 2011 and 2012. For more details refer Appendix-G to Appendix- L

Year

No of EF/ OC/ EF+OC (outage duration less than 20 min)

Avg. feeder loading before the fault (A)

2010 2709 97.62011 3110 110 2012 3395 101.3 Avg. per year 3071 103 Avg. per month 255 ‐Failure/month/feeder 3.4 ‐

Table 6.3: GSS Feeder failure data (EF and OC with outage duration less than 20

min)

Major portion of above mentioned faults may have occurred in the protection zone-1

marked on Figure 6.2 Therefore we can come to an conclusion that there must be

similar number (even greater) of temporary faults occurred downstream of branch

protection auto re-closures which may cause auto re-closures to lockout.

39

.

Figure 6.2: Protection zones in a typical 33 kV radial distribution feeder.

Once auto re-closure got into lockout state it must be reset by the operator locally or

remotely. Without any means of automation only available option is to reset the re-

closure locally. Depend upon the location of the re-closure; time taken by field staff

to reset a re-closure may vary from 20 min~ 45 min in average. This time includes

the time taken to detect the outage (typically 10 min) and crew travel time. During

stormy days it may take much longer time due to higher number of breakdowns.

Therefore 25 min time (Response time 10 min + Crew Travel time 10 min +

Restoration time 5 min) duration considered as an average time taken by the field

staff to reset a lockout re-closure.

According to table 6.3 average failures (EF and OC with outage duration less than 20

min) per year is 3071and average feeder loading just before the fault is 103 Amps.

Above information can be used to determine annual loss of electricity sales in kWh

due to above mentioned failures.

Following factors considered during the calculation.

• Power outages less than 20 min. considered for calculation

• 33% (Considering three branch protection zones per feeder & loading of a

branch were considered as a 1/3rd of the total feeder loading) of the feeder

40

loading at the time of feeder tripping considered for loss of energy calculation

for a particular power outage.

• Network power factor considered as 0.9

• Profit margin of LKR 2.70 were calculated from 2012 financial data of WPN

and used the same value for year 2010 and 2011 (Refer Appendix M for

more details)

Average Failures (EF and OC with outage duration less than 20 min)

per yr.

= 3071

Average feeder loading just before the fault

=103 A

Time taken to reset a re-closure =25 min

Annual loss of electricity sales =0.33x103x33x0.9x1.732x(25/60)x3071

=2237299 kWh

Annual saving by reducing the

Outage duration =2237299x2.7

=6,040,707.96 LKR

6.2.2 Reduction in Manpower due to reduction in Crew travel time

Following factors were considered for the calculation

No of Workers involved in breakdown restoration = 3 Workers

Worker hourly rate =200.00 LKR

Avg. Transportation cost =800.00 LKR

Travel time (to return trip) = 35 min

Cost of crew travel time per single fault = [3x200x(35/60)+800]

=1150.00 LKR

Annual saving due to reduction in crew travel time =1150x3071

=3,531,650.00 LKR

41

6.3 Cost Benefit Analysis

Following cost benefit analysis gives simple payback period of 5.4 years and 14%

Project IRR even without considering all the benefits that we get out of distribution

automation. Therefore implementing distribution automation can be considered as

economically feasible.

Capital Expenditure 18 Rs. Millions

OandM cost

Wages 4.68 Rs. Millions

Telecommunication 0.625 Rs. Millions

Spares 0.36 Rs. Millions

5.665 Rs. Millions

Cost Saving due to Automation

Reduction in outage Duration 6.00

Rs. Millions

Reduction in Crew Travel time 3.53

Rs. Millions

9.53

Rs. Millions

Profit and Loss Statement

Year 0 1 2 3 4 5 6 7 8 9 10

Reduction in outage Duration 6.00

6.00

6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00

Reduction in Crew Travel time 5% 3.53 3.71 3.89 4.09 4.29 4.51 4.73 4.97 5.22 5.48 Total Savings (Rs Millions) 9.53 9.71 9.89 10.09 10.29 10.51 10.73 10.97 11.22 11.48 OandM cost 5% 5.67 5.95 6.25 6.56 6.89 7.23 7.59 7.97 8.37 8.79 Depreciation 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 Finance cost 0.5 0.4 0.3 0.2 0.1 Profit before tax 1.6 1.6 1.6 1.6 1.6 1.5 1.3 1.2 1.0 0.9 Tax (0% and 30%) 0% 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Profit After Tax 1.6 1.6 1.6 1.6 1.6 1.5 1.3 1.2 1.0 0.9

Cash Flow

Profit After tax 1.6 1.6 1.6 1.6 1.6 1.5 1.3 1.2 1.0 0.9 Add Depreciation 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 Finance cost 0.5 0.4 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0

Net Flow of Project (18.00) 3.87 3.76 3.65 3.53 3.40 3.28 3.14 3.00 2.85 2.69

Project IRR 14.0% NPV 20.98 SPP (Years) 5.4 Less Finance cost 0.5 0.4 0.3 0.2 0.1 Capital repayments 2.2 2.2 2.2 2.2 2.2

Cash Inflow (7.20) 1 1 1 1 1 3 3 3 3 3

Equity IRR 20%

42

Chapter 7

EQUIPMENT IDENTIFICATION AND GRAPHICS SCREEN DEVELOPMENT

Equipment numbering and identification is a mandatory requirement in the industry.

Therefore equipment identification and numbering scheme were developed before

moving in to the implementation part of distribution automation.

7.1 Equipment Numbering Scheme

Medium voltage network can be divided in to two main sections.

1. MV Lines

2. MV switchgears

7.1.1 MV Line Numbering Scheme

MV lines can be classified in to three main categories.

• MV lines fed by Grid Substations

• MV lines fed by Primary Substations

• MV lines fed by Gantries.

MV Segment Numbering

Above mentioned MV line can be further divided into smaller units called MV

segments. MV segment is a section of MV line bounded by a set of isolation devices.

It can be seen that, for n- number of Isolation devices in a particular MV feeder

(Excluding source isolation device), there are (n+1) number of MV segments

available. Figure 7.1 shows MV segments defined in Feeder 01 of Wattala PSS. It

can be seen that there are 3 nos. isolation devices and 4 nos. MV segments.

During implementation, these MV segments were numbered with multiples of tens to

accommodate newly added segments in later stages.

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Figure 7.1: MV Line segment of Feeder 01 –Wattala PSS.

MV Feeder numbering

Each MV feeder was given a five digit unique name. Naming convention is as

follows.

1stdigit represent the source of the feeder (Grid, Primary Sub, Gantry)

2ndand3rd Lettering denotes the name given to the source

4thand 5th digits denotes the feeder number.

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With the help of the feeder number and MV segment, any part of the medium voltage

network can be identified.

Eg. [1Ve07/010] refers to the 1st MV segment of the Feeder 07 of Veyangoda Grid

Substation

7.1.2 MV switchgear Numbering Scheme

Each MV switchgear was given a four digit name. Naming convention is as follows.

1stcharacter represent the consumer service center it belonging to

2ndcharater denotes the type of the switchgear

3rdand 4th digits denote the switchgear sequential number.

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7.2 Graphics Screen Development

Graphics screens are used to convert field collected data into visually meaningful

data. It works as a human machine interface.

7.2.1 Color scheme and symbol definition

It is very important to adopt unique color scheme and set of symbols before starting

the graphics screen development.

Status Color Voltage Level

Energized Magenta 33 kV

Yellow 11 kV

Deenergized White All

Grounded Green All

Overload Red (Blinking) All

7.2.2 Graphics screen development in Iconics Genisis64

Graphics screens need to be arranged in a proper order to provide user friendliness to

its operators and they were grouped under following major categories.

• Main screen

• Medium voltage network overview screen (Single line and Geographical

view)

• Gantry arrangement screens

• Primary substation arrangement screens

• Grid substation arrangement screens

• Real time alarm screens

• Historical alarm screens

• Trending and graphing screens

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GraphWorX64 is the ICONICS application to create graphics screens for runtime

operators. Figure 7.2 shows Graph WorX 64 application interface.

Single lines were first drawn by Auto cad and saved in vector graphics format

(.wmf). These vector graphics can then be imported in to Graph WorX 64

environment. This has speed up the graphics screen development work greatly.

Templates were used for enforcing a uniform look-and-feel among displays.

Templates include uniform background colors and screen navigation bar. Figure 7.3

shows Template in the Layout Tab of the GraphWorX64 Ribbon Figure 7.4 shows

the template created for Control center SCADA of WPN.

Figure 7.2: Graph WorX 64 application interface.

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Figure 7.3: Templates in the Layout Tab of the GraphWorX64 Ribbon

Figure 7.4: SCADA Main Screen

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Figure 7.5: Display screen for 33 kV Gantry

Figure 7.6: Display screen for Auto Re-closure Operation

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Chapter 8

DATA LOGGING, TRENDING, ANALYZING AND ALARM GENERATION

Data collected at field installed devices need to be stored for future reference.

Plotting these historical data (such as feeder currents) in graphs enable, network

operator to get more understanding of the network situation in a given time. Alarms

draw immediate attention of the operators to network emergencies. Therefore it is

very important to log historical data, trending them for analyzing and generate alarms

for network emergencies.

8.1 Data Logging

TrendWorX64 Logger is a server application that is installed as part of the

GENESIS64 suite. It handles data logging and data retrieval among multiple types of

databases. The logger collects data from an OPC data source and sends that data to a

SQL server database such as Microsoft SQL Server 2005/2008. Its basic function is

to collect and log data for analysis [14].

Figure 8.1: Trend WorX 64 Logger

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In order to log data, database group that specifies how to connect a database to store

the information must be created. It is possible to have one or more database groups

for a trend configuration. Each database group acts as a physical connection to the

database, and manages data updates and logging activities.

Figure 8.2: TrendWorX64 Logger Database Group - Database Connection Tab

8.2 Data Trending

The ICONICS TrendWorX64 viewer is a client application that provides real-time

and historical data trend displays within the GENESIS64 application environment.

The viewer communicates with, OPC DA, and OPC HDA servers to provide trend

displays based on the connections to the data source that specify.

The TrendWorX64 Viewer has three different modes: Configuration mode, Runtime

mode, and Freeze mode. Configuration mode is design for changing the properties.

In Runtime mode the data is collected and displayed and the chart updates according

to the data received from the OPC servers. During runtime, operator can freeze the

display and examine the data in it. The data still collects, but the display stops

updating with current data until operator leaves freeze mode.

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Figure 8.3: TrendWorX64 Viewer Properties

Figure 8.4: Display screen for plotting historical feeder loading

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8.3 Alarm Configuration

AlarmWorX64 is an alarm and events management system available in the standard

GENESIS64 suite of application. AlarmWorX64 offers the tools need to deliver real-

time alarm information throughout the system. AlarmWorX64 is a family of modular

alarming products, including the Alarm Server, the Alarm Logger and the Alarm

Viewer Control.

8.3.1 AlarmWorX64 Server

The AlarmWorX64 Server receives field data from OPC Data Access servers and

performs alarm detection and reporting on that data. AlarmWorX64 Server interface

was used to create and maintain a database configuration of alarm tags.

All alarm detection and reporting that it does conforms to OPC Alarm and Events

standards. Event notifications generated by the AlarmWorX64 Server are sent to

OPC clients (such as, AlarmWorX64 Viewer and AlarmWorX64 Logger) that

subscribe to it. Alarm tags templates were created to reduce development time.

Alarm tags were grouped in to areas so that filtering of alarms based on areas made

easy.

Figure 8.5: AlarmWorX64 Server configuration

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8.3.2 AlarmWorX64 Viewer

The AlarmWorX64 Viewer is client application that provides real-time and historical

alarm information within the GENESIS64. The AlarmWorX64 viewer can be used to

view alarms, acknowledge alarms and do simple alarm analysis. AlarmWorX64

viewer added onto a GraphWorX64 design surface to create real time and historical

alarm views of SCADA system in WPN control center.

Figure 8.6: Display screen to display Real time Alarms.

8.3.3 AlarmWorX64 Logger

The AlarmWorX64 Logger provides a permanent copy of alarm and event

notifications. The alarm and event notifications are generated by AlarmWorX64

Server. AlarmWorX64 Logger subscribes to AlarmWorX64 Server and stores the

information in a database.

Configuration for the AlarmWorX64 logger is stored in an MS SQL database.

The configuration database can host many logging configurations. A logging

configuration stores information, such as the database connection, to store the alarm

and event data and the subscription to the OPC AE server.

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Figure 8.7: AlarmWorX64 Logger Configuration.

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Chapter 9

PROJECT IMPLEMENTATION

Distribution code issued by Public utilities commission in 2012 has urged

distribution licensees to establish Distribution Network Control Centers covering

their respective operating areas. As a result establishing a control center with

SCADA system was included in Medium Voltage development plan of Western

province North- Ceylon Electricity Board. It paved the way to implement the

findings of this work in a real engineering application.

Figure 9.1 shows the functional interrelationship of the key units involved in medium

voltage network operation. Outage information as well as status of the network can

be obtained through details gathered by call center. Operational staffs, uses SCADA

system to control and monitoring medium voltage network. Feeder failure and outage

information passed to breakdown restoration teams operated in the field level and

their geographical location monitored through GPS tracking system. This enables

speedy supply restoration during a power outage.

Figure 9.1 Functional inter relationship of various units in WPN Control center.

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9.1 Project Overview

Western Province North is divided in to 6 areas; Gampaha, Kelaniya, JaEla,

Negombo, Divulapitiya and Veyangoda) for administrative purposes. The reliability

of the 33 kV distribution network is so important, as the country’s main industrial

zones (Biyagama EPZ, Katunayaka EPZ) andmain International airport lies within

the province.

Figure 9.2 Statistical data of Western province north. (Source Medium Voltage plan

2011) Area No. of

Consumers* Power Demand. Energy Sales. GWh/Yr. Revenue (MW) Dist Bulk Total MRs./Yr

1. Kelaniya 103,554 77 112 362 474 7,869 2. JaEla 82,070 106 95 454 549 4,572 3. Gampaha 96,850 48 97 34 131 1,804 4. Negombo 85,085 56 91 290 381 5,958 5. Veyangoda 80,553 38 73 40 113 1,409 6.Divulapitiya 57,571 35 50 53 103 1,226 Total 509,845 360 518 1233 1775 22,838

Table 9.1: Power Demand and Energy Sales Data- 2010

Land area 1421 km2

Population 2.5 Million

Geographical Demarcation Gampaha District

Electrified Houses 465,010

Households 492,878

Percentage of Electrified Houses 94.34%

Peak Power Demand 360 MW

Energy Demand 1814.3 GWh/Yr

Average load factor 57.53%

Demand Density 253.34 kW/km2

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Area 33kV-OH

(km) % 11kV-OH

(km) %

Kelaniya 447 22 26 18 JaEla 342 17 95 67 Gampaha 346 17 Negombo 287 14 22 15 Veyangoda 329 16 Divulapitiya 278 14 Total 2,029 100 143 100 Table 9.2: HT Lines Length (route length) (According to the progress report April 2010) Distribution network of WPN currently fed by 11 grid Substations (GSS) and

supported with 40 Gantries and 16 Primary substations (PSS).

By considering the magnitude of the project, implementation has been proposed in

five stages.

1. Stage-1 : Procurement of Control center Equipment (SCADA

software, video wall, Server computer, IT infrastructure, etc.)

2. Stage-2 : Automation of 33 kV Distribution Gantries

3. Stage-3 : Status Monitoring of 33 kV feeders coming out from Grid

substations

4. Stage-4 : Automation of 11 kV Primary substations

5. Stage-5 : Installing Fault location system for 33 kV overhead network

with Lightning location system and integrate it with the SCADA system

6. Stage-6 : Installing of Online transformer condition monitoring system

in PSS 33/11 kV transformers and link it with the SCADA

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9.2 Project Schedule

Detailed project schedule attached in Appendix N.

9.2.1 Stage-1: Procurement of Control center Equipment (SCADA software,

video wall, Server computer, IT infrastructure, etc.)

9.2.2 Stage-2: Automation of 33 kV Distribution Gantries

9.2.3 Stage-3: Status Monitoring of 33 kV feeders coming out from Grid

substations

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9.2.4 Stage-4: Automation of 11 kV Primary substations

9.2.5 Stage-5: Installing Fault location system for 33 kV overhead network

with Lightning location system and integrate it with the SCADA

system

9.2.6 Stage-6: Installing of Online transformer condition monitoring system in

PSS 33/11 kV transformers and link it with the SCADA

9.3 Equipment Installation

9.3.1 Stage-1: Procurement, installation and TandC of Control center

Equipment (SCADA software, video wall, Server computer, IT

infrastructure, etc.)

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This stage mainly deals with the infrastructure development at distribution control

center of WPN. Obtaining necessary approvals for procurement, preparation of

suitable specification and bidding documents were given high priority. Following

items were mainly procured and installed under this stage [15].

• SCADA software (Development and runtime license)

• OPC Server Software for SCADA

• 600 VA UPS for Control center PCs

• 24 inch LCD displays for Operator consol

• 120 inch seamless LCD display for SCADA video Wall

• Low end Server Computer (SCADA development and server station)

• Multi Monitor Controller for Operator Consol

• Quad Display Computer for video wall

• Desktop PC (SCADA Client station)

Figure 9.2 shows single line diagram of display screen inter connection.

Figure 9.3: Single line diagram of display screens.

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Figure 9.4: Operator Consol.

Figure 9.5 120 inch video wall installation.

Figure 9.6 120 inch video wall in operation.

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9.3.2 Stage-2: Automation of 33 kV Distribution Gantries

33 kV Distribution gantries are used to subdivide 33 kV feeders coming out from

Grid substations. Outgoing feeders of gantries normally fitted with Automatic re-

closures. These re-closures operates to minimize grid substation feeder failures due

to earth faults and over currents in distributer lines downstream of the auto re-

closures.

Figure 9.6 shows typical arrangement of a 4 section double bus bar gantry.

Figure 9.7 Ekala Gantry (Four Section Double bus bar)

IP modems were fitted to each auto re-closure link with SCADA server over GPRS.

Auto re-closures communicate in DNP3 protocol.

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Figure 9.8 Auto re-closure automation works- Ganemulla Gantry

Figure 9.9Auto re-closures automation works- Minuwangoda Gantry.

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Figure 9.10 Auto re-closure automation works- Ragama Rd. Kadawatha.

After establishing data connectivity with the SCADA server, auto re-closure data can

be viewed real time through SCADA system. Figure 9.10 shows data related to auto

re-closure located at Ragama Rd. Kadawatha.

Figure 9.11Real time status monitoring of auto re-closure locat

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