STANDARDS/MANUALS/ GUIDELINES FOR SMALL ......STANDARDS/MANUALS/ GUIDELINES FOR SMALL HYDRO...

STANDARDS/MANUALS/ GUIDELINES FOR SMALL HYDRO DEVELOPMENT

3.4 Electro-Mechanical– Selection of Control, Automation, Protection and Monitoring System

Sponsor: Ministry of New and Renewable Energy Govt. of India

Lead Organization: Alternate Hydro Energy Center Indian Institute of Technology Roorkee

July 2012

Contact: Dr Arun Kumar Alternate Hydro Energy Centre, Indian Institute of Technology Roorkee, Roorkee - 247 667, Uttarakhand, India Phone : Off.(+91 1332) 285821, 285167 Fax : (+91 1332) 273517, 273560 E-mail : [email protected], [email protected]

DISCLAIMER The data, information, drawings, charts used in this standard/manual/guideline has been drawn and also obtained from different sources. Every care has been taken to ensure that the data is correct, consistent and complete as far as possible. 3.2 The constraints of time and resources available to this nature of assignment, however do not preclude the possibility of errors, omissions etc. in the data and consequently in the report preparation. Use of the contents of this standard/manual/guideline is voluntarily and can be used freely with the request that a reference may be made as follows: AHEC-IITR, “3.4 E&M Works – Selection of Control, Automation, Protection and Monitoring System”, standard/manual/guideline with support from Ministry of New and Renewable Energy, Roorkee, July 2012.

PREAMBLE

There are series of standards, guidelines and manuals on electrical, electromechanical aspects of moving machines and hydro power from Bureau of Indian Standards (BIS), Rural Electrification Corporation Ltd (REC), Central Electricity Authority (CEA), Central Board of Irrigation & Power (CBIP), International Electromechanical Commission (IEC), International Electrical and Electronics Engineers (IEEE), American Society of Mechanical Engineers (ASME) and others. Most of these have been developed keeping in view the large water resources/ hydropower projects. Use of the standards/guidelines/manuals is voluntary at the moment. Small scale hydropower projects are to be developed in a cost effective manner with quality and reliability. Therefore a need to develop and make available the standards and guidelines specifically developed for small scale projects was felt.

Alternate Hydro Energy Centre, Indian Institute of Technology, Roorkee initiated an exercise of developing series of standards/guidelines/manuals specifically for small scale hydropower projects with the sponsorship of Ministry of New and Renewable Energy, Government of India in 2006. The available relevant standards / guidelines / manuals were revisited to adapt suitably for small scale hydro projects. These have been prepared by the experts in respective fields. Wide consultations were held with all stake holders covering government agencies, government and private developers, equipment manufacturers, consultants, financial institutions, regulators and others through web, mail and meetings. After taking into consideration the comments received and discussions held with the lead experts, the series of standards/guidelines/manuals are prepared and presented in this publication.

The experts have drawn some text and figures from existing standards, manuals, publications and reports. Attempts have been made to give suitable reference and credit. However, the possibility of some omission due to oversight cannot be ruled out. These can be incorporated in our subsequent editions.

This series of standards / manuals / guidelines are the first edition. We request users to send their views / comments on the contents and utilization to enable us to review for further upgradation.

Standards/ Manuals/Guidelines series for Small Hydropower Development General 1.1 Small hydropower definitions and glossary of terms, list and scope of different

Indian and international standards/guidelines/manuals 1.2 Part I

Planning of the projects on existing dams, Barrages, Weirs

1.2 Part II

Planning of the Projects on Canal falls and Lock Structures.

1.2 Part III

Planning of the Run-of-River Projects

1.3 Project hydrology and installed capacity 1.4 Reports preparation: reconnaissance, pre-feasibility, feasibility, detailed project

report, as built report 1.5 Project cost estimation 1.6 Economic & Financial Analysis and Tariff Determination 1.7 Model Contract for Execution and Supplies of Civil and E&M Works 1.8 Project Management of Small Hydroelectric Projects 1.9 Environment Impact Assessment 1.10 Performance evaluation of Small Hydro Power plants 1.11 Renovation, modernization and uprating 1.12 Site Investigations Civil works

2.1 Layouts of SHP projects

2.2 Hydraulic design 2.3 Structural design 2.4 Maintenance of civil works (including hydro-mechanical) 2.5 Technical specifications for Hydro Mechanical Works

Electro Mechanical works

3.1 Selection of Turbine and Governing System 3.2 Selection of Generators and Excitation Systems 3.3 Design of Switchyard and Selection of Equipment, Main SLD and Layout 3.4 Monitoring, control, protection and automation 3.5 Design of Auxiliary Systems and Selection of Equipments 3.6 Technical Specifications for Procurement of Generating Equipment 3.7 Technical Specifications for Procurement of Auxiliaries 3.8 Technical Specifications for Procurement and Installation of Switchyard

Equipment 3.9 Technical Specifications for monitoring, control and protection 3.10 Power Evacuation and Inter connection with Grid 3.11 operation and maintenance of power plant 3.12 Erection Testing and Commissioning

PERSONS INVOLVED

1. Dr Arun Kumar, CSO & Principal Investigator ,AHEC,IIT, Roorkee 2. Dr S K Singal, SSO & Investigator,AHEC,IIT, Roorkee

Drafting Group

1. Mr. S.K.Tyagi, Consultant, AHEC,IIT, Roorkee 2. Prof. O.D.Thapar,Consultant, AHEC,IIT, Roorkee

Consultation Group 1. Dr Arun Kumar,AHEC,IIT, Roorkee 2. Mr S.N.Singh, AHEC,IIT, Roorkee 3. Dr S K Singal,AHEC,IIT, Roorkee 4. Prof. H.K.Verma,Elect.Engg., IIT, Roorkee 5. Mr. S.C.Jain, Consultant, AHEC,IIT, Roorkee 6. Mr. A.K.Chopra, Consultant, SHP, MNRE,GOI, New Delhi 7. Mr. Jugal Kishore, Consultant, Hardwar 8. Mr. R.B.Saxena, Consultant, Chandigarh 9. Mr. Surendra Singh ,PGCL, PEDA,Chandigarh 10. Mr. Pankaj Kulshreshtha, UJVNL, Dehradun 11. Mr. P.K.Singhal, UPJVNL, Lucknow 12. Mr. V.K.Sharma, THDC, Rishikesh 13. Mr. U Ukhal, HPPCL, Himachal Pradesh 14. Mr..S.S.Sidhu, HPP India Pvt. Ltd, Noida 15. Mr. K.C.Arora, Pentaflo Hydro power Ltd 16. Mr. P.K.malohtra, Pentaflo Hydro power Ltd 17. Mr. Sanjeev Handu, Andriz Hydro power Ltd. 18. Mr. Vishnupad Saha, Andriz Hydro power Ltd. 19. Mr. Dinesh Rajput, Andriz Hydro power Ltd. 20. Mr. Pradeep Dube, Tanushree Hydropower Consultants, Noida 21. Mr. H.M.Sharma, Jyoti Ltd.,Vadodra 22. Mr. Viral B Mahida, Jyoti Ltd.,Vadodra 23. Mr. Nishant Saha, Jyoti Ltd.,Vadodra

CONTENTS ITEMS PAGE NO Section-I Introduction 1 1.1 Objectives 1 1.2 General 1 1.3 References and Codes 1 Section-II Control and Automation 4 2.1 General 4 2.2 Technology-Control System 4 2.3 Control Functions 5 2.4 Considerations for Selecting Control System 12 2.5 Categorization of Control System 13 2.6 System Architecture, Communication and Databases 15 2.7 Control Data Networks 15 2.8 Human-Machine Interface (HMI) 17 2.9 Hardware 17 2.10 Grounding 17 2.11 Static Control 17 2.12 Information and Control Signals 18 2.13 Communication Links 19 2.14 Control Systems for Various Categories of MHP & SHP 20 2.15 Recommendation for Automation and Control 35 Section-IV Protection and Relaying 37 3.1 General 37 3.2 Abnormal Conditions 38 3.3 Devices Used In A Typical Protection System 39 3.4 Devices used in a Typical Protection System 44 3.5 Generator Protection System and Relay Selection 46 3.6 Generator Transformer Protection 55 3.7 Line Protection 59 3.8 Recommendations for Protection and Relaying 63 Section-IV Metering and Monitoring 64 4.1 Metering and Monitoring 64 4.2 Requirements of Monitoring System 66 4.3 Recommendations for Metering and Monitoring of SHP 67

LIST OF FIGURES FIGURE NO. TITLE PAGE NO. 1 Typical Turbine Control 6 2 Typical Generator Controls 7 3 Overview of Typical Plant Automatic Control 7 4 Start-Stepped Sequence Control for Synchronous generator 8 5 Controlled Action Shut Down (Typical for gen. units above 5

MW) 10

6 Emergency Shut Down (Typical for Gen. Units above 5 MW) 11 7 Electrical Shut Down (Typical for Synchronizing Generator

above 5 MW) 14

8 Typical Relationship of local centralized and off site control function

15

9 Typical System Configuration Canal SHP project (Punjab) 25 10 Typical Single Line Diagram for 2 x 3.5 MW SHP 26 11 Typical PLC Controller with PC SCADA (Control &

Protection System) for a (2 x 3.5 MW) 27

12 Typical General Arrangement of Control & Protection 28 13 Typical Control and Protection of a SHP (4 x 4 MW) 29 14 Typical Configuration for Computerized Hydro Station

(above 5 MW) 30

15 Typical HMI System for a 2 unit Computerized Station with offsite Control

31

16 Typical Computerized Control & Monitoring System - Grounding Scheme

36

17 Typical single line diagram for asynchronous generators 49 18 Typical single line diagram for synchronous generators 50 19 Typical Single Line Diagram for generating Units above

5MW 51

20 Typical Unit Metering Single Line Diagram for generating Units above 5MW

52

21 Typical Functional Overview - Numerical Generator Protection Relay

54

22 Typical Multifunction Generator Relays 56 23 Typical Generator Control Panel 57 24 Typical Functional Overview – Transformer Differential

Protection 59

25 Schematic Drawing – 6 MVA, 11/33 kV Gen. Trans. Protection Single Line Diagram

60

26 Typical SHP Grid Interconnection – Two Terminal 66 kV (Short & important) Line Protection

61

27 Schematic Drawing for 33 kV Line Protection for 4 x4 MW Project

62

LIST OF TABLES TABLE NO. TITLE PAGE NO.

1 Controlled Action Shut Down 9 2 Emergency Shut Down 9 3 Electrical Shut Down 12 4 Comparison of various options for control system, including

turbine governing supervisory control and data acquisition16

5 Communication Links 19 6 Micro Hydro Quality Standards 20 7 List of Sensors 33 8 Recommendations for automation and control 35 9 Abnormal Conditions of Mechanical Equipment of plant 38 10 Abnormal Conditions of Electrical Equipment of plant 38 11 Abnormal conditions of Auxiliaries and grid 39 12 Protective Devices 39 13 Features of Relays 40 14 Protection elements of a Microprocessor based relay 43 15 Protection of Turbine 45 16 Protection of generator 45 17 Monitoring and protection scheme 47 18 Requirements of Protection of Turbine 47 19 Requirements of Protection of Generator 48 20 Summary of numerical relay protection 54 21 Typical multi function digital differential protection relay 5822 Recommendations for protection and relaying 63 23 Data required for monitoring 64 24 Recommendations for metering and monitoring 67

LIST OF ANNEXURES ANNEXURE

NO. TITLE PAGE NO.

1 List of Generator Panel Indication and Relays 68 2 List of Protection Elements in Micro Processor based Relays 69

AHEC-IITR/MNRE/SHP Standards/E&M Works- Guidelines for Selection of Control, Automation, Protection and Monitoring System 1

SELECTION OF CONTROL, AUTOMATION, PROTECTION AND MONITORING SYSTEM

SECTION-I

INTRODUCTION 1.1 SCOPE

This standard/ mannual guideline covers selection of systems for control, automation,

protection and monitoring for small hydropower (SHP) up to 25 MW by developers, manufacturers, consultants, regulators and others. This includes selection of technology, extent of automation and monitoring system for different categories of SHP (up to100 kW, up to 5 MW and 5 MW to 25 MW) which are economical, easy to adopt, sustainable, feasible and essential for safe operation.

1.2 GENERAL The generating units of a SHP plant may have its shaft vertical, horizontal or inclined

with the type of turbine selected to suit the site’s physical conditions. Small hydro turbines may be selected as per site conditions, head and discharge available. Small hydro-generator are of the alternating current type and may be either synchronous or induction type. Usually SHP units up to 5 MW are expected to require minimum of field assembly and installation work. While units having capacity from 5 MW to 25 MW may have slow speed, large diameter and with split generator, stator that may require final winding assembly in the field.

Mini & micro power stations are generally provided system suiting to these being run

unattended or with few attendants while bigger machines up to 25 MW capacity have more elaborate arrangement of control monitoring and protection. Provision of parallel operation with other systems will have more comprehensive control, monitoring & protection system.

This guideline will serve as a reference document along with available national &

international codes, standards, guide and books. For the purpose of convenience this standard / manual guidelines has been subdivided as follows: (i). Control and Automation (ii). Protection and Relaying (iii). Metering and Monitoring

1.3 REFERENCES AND CODES

(R1). IEEE 1020:1988 - IEEE guide for control of small hydro electric power plants

(R2). IEEE 1010:2006 - IEEE guide for control of hydro electric power plants


(R3). IEEE 60545:1976 - Guide for commissioning operation and maintenance of Hydraulic Turbines

(R4).IEC 61116:1992 - Electro mechanical guide for small hydroelectric installations

(R5). IEC: 62270:2004 Hydroelectric power plant automation – Guide for computer based control

(R6). IEEE 1046:1991 - IEEE application guide for distributed digital control and monitoring for power plants

(R7). IEEE 1249:1996 - IEEE guide for computer–based control for power plant automation

(R8). IEEE C 37.101:2006 - IEEE guide for generator ground protection (R9). IEEE C37.1:2007 IEEE Standard for SCADA and Automation

systems (R10). IEEE 421.4-2004 - IEEE guide for preparation of excitation system

specification (R11). ANSI/ IEEE 242:1996 - IEEE recommended practice for protection and

coordination of industrial and commercial power systems

(R12). ANSI/ IEEE C 372-1987 - IEEE standard electrical power systems device function numbers

(R14).ANSI/ IEEE C 37.102:1987 - IEEE guide for generator protection (R15) IEEE C37.102 :2006 - IEEE Guide for AC Generator Protection (R16). AHEC IITR - Micro-Hydro Quality Standards-2005

For preparing this publication following published and unpublished documents were also referred and contents used:

(i) AHEC, 1997,Technology recommended under UNDP-GEF Project for Himalayan SHP project, Ministry of Non Conventional Energy Sources, Delhi

(ii) World Bank. 1991, “India - Mini-hydro development on irrigation dams and canal drops pre-investment study”, Report ; no. ESM 139 91. Energy Sector Management Assistance Programme. Vol. 1-3.

(iii) Thapar, R and Perrault DA, 1985 “Economic Computer Controls for Low Head Hydro”; Waterpower’85, Las Vegas, USA, September 25-27, 1985

(ii) Thapar, R, 1986, “Microprocessor Controller for a small Hydroelectric System”, IEE, October, 1986

(iii) DIGITEK INC , 1994, “Microcomputer Based Control and Monitoring Systems”;. 11807, North Creek Pkwy, So. Bothell, WA 98011 U.S.A. – Technical Literature.

(iv) Thapar OD, 1985, “Small Hydro Electric Technology for Economic Development”, Proceedings of XI National Convention of Electrical Engineers on “Environmental Friendly Electric Power Generation”, Nov. 1995, Roorkee. Allied Publisher pp 44-51

(v) AHEC 2002, Report on study and design and development of Model SHP based self sustained projects - E & M Equipment standardization and cost reduction Vol. III, Power finance corporation Ltd.


Abbreviations:

ANSI : American National Standards Institute AHEC IITR : Alternate Hydro Energy Centre, Indian Institute of Technology, Roorkee

IEC : International Electro-technical Commission IEEE : Institute of Electrical & Electronic Engineers


SECTION-II CONTROL AND AUTOMATION

2.1 GENERAL For small hydro installation simplicity of control system is advised, however, the

sophistication of control should be based on the complexity and size of the installation, without compromising unit dependability and safety of personnel. Simplicity of control is desirable to keep total cost of installed equipment as well as cost of maintenance, repair and testing at economical level. Moreover a simpler system is more reliable as compared to complex one.

2.2 TECHNOLOGY - CONTROL SYSTEM 2.2.1 Conventional Control System Up to 1980s, conventional control system was almost universally used. In this system

control of a hydro plant’s generating units was typically performed from governor panel or unit control switchboard. If the plant had multiple units, a centralized control board was provided. The unit control board and centralized control board using relay logic contained iron vane meters, hardwired control switches, and hundreds of auxiliary relays to perform the unit start/stop and other control operations. All the necessary sensors and controls required to operate the unit or units were hardwired to the unit control board and/ or centralized control board, allowing operator to control the entire station from one location. Stepped sequence control system was mostly followed. Large hydro stations mostly had operators at two levels i.e. governor gallery and centralized control room. Offsite supervisory control was by hardwires and not successful. Data acquisition was manual. Modernization of the conventional control system using digital control technology is now being undertaken.

2.2.2 Modern Control System Modern systems permit control of the entire plant from a single location. Modern control

rooms utilize the far more cost-effective supervisory control and data acquisition (SCADA) systems (including programmable logic controllers (PLCs) and distributed computer control systems with graphic display screens to implement a vast array of control schemes. The SCADA control scheme also provides flexibility in control, alarming, sequence of events recording, and remote communication that was not possible with the hardwired control systems. Data acquisition, storage and retrieval is provided by the computer.

For complete reference computerized automation, remote control and SCADA reference

be made to IEC 62270: 2004 “Hydroelectric power plant automation – Guide for computer based control”.


The main control and automation system in a hydroelectric power plant are associated with following:

(i). Turbine governor for speed control (frequency) optimum running control for real

power generation and dynamic stability. (ii). Generator excitation control for voltage reactive power control Plant automation to

cover such operation as start, stop, synchronizing and running control of the unit. (iii). Supervisory control including off site control and centralized control room. (iv). Data acquisition and retrieval is used to cover such operations as relaying plant

operating status, instantaneous system efficiency, or monthly plant factor, to the operators and managers.

The control and monitoring equipment for a hydro power plant include control

circuits/logic, control devices, indication, instrumentation, protection and annunciation at the main control board and at the unit control board for generation, conversion and transmission operation including grid interconnected operation of hydro stations. These features are necessary to provide operators with the facilities required for the control and supervision of the station’s major and auxiliary equipment. In the design of these features consideration must be given to the size and importance of the station with respect to other stations in the power system, location of the main control room with respect to the equipments to be controlled and all other station features which influence the control system.

Modern practice for control of hydroelectric plants is based on the combination of

computer based and non-computer based equipment utilized for unit, plant and system control.

2.2.3 Modern Control of Power Station Modern control system employed for large power stations (above 5 MW) is distributed

computer control system with adequate redundancy. Modern control of small hydro up to 5 MW is mostly PLC based integrated governor and

plant control systems. Micro hydro modern controls are micro processor based non flow control electronic load

controller. 2.3 CONTROL FUNCTIONS There are many functions to be controlled in a small hydropower system. For example

turbine governor controls the speed of turbine, plant automation covers operations as auto start, auto synchronization, remote control startup or water level control and data acquisition and retrieval covers such operation as relaying plant operating status, instantaneous system efficiency or monthly plant factor.


2.3.1 Turbine Control This is the speed / load control of turbine in which governor adjusts the flow of water

through turbine to balance the input power with load. In case small plants in the category of micro hydro (100 kW unit size), load controllers

are used, where excess load is diverted to dummy load to maintain constant speed. With an isolated system, the governor controls the frequency of the system.

In interconnected system, the governor may be used to regulate unit load and may

contribute to the system frequency control. Figure -1 shows the different types of control applicable to turbines.

Fig.1 : Typical Turbine Control

2.3.2 Generator Control

This is the excitation control of synchronous generator. The excitation is an integral part of synchronous generator which is used to regulate operation of generator. The main functions of excitation system of a synchronous generator are: (i). Voltage control in case of isolated operation and synchronizing (ii). Reactive power or power factor controls in case of inter connected operation.

The different generator controls are shown in fig. 2.

2.3.3 Plant Control Plant control deals with the operation of plant. It includes sequential operation like startup, excitation control, synchronization, loading unit under specified conditions, normal shutdown, emergency shutdown etc. The mode of control may be manual or automatic and may be controlled locally or from remote location. Plant control usually includes monitoring and display of plant conditions. Different plant controls are given in fig -3.

TURBINE CONTROL

FLOW CONTROL

(GOVERNOR)

MAIN DISCHARGE - NEEDLE - GUIDE VANE - WICKET GATE

BY PASS DEFLECTOR

SPEED CONTROL

LEVEL CONTROL

KW CONTROL


Typical function of start, stop and sequence logic as specified for 4 x 4 MW project is given in figure 4 to figure 7.

Fig. 2 : Typical Generator Controls

Fig. 3: Overview of Typical Plant Automatic Control

(INCLUDING CENTRALISED CONTROL ROOM)


Fig. 4 : Start-Stepped Sequence Control for Synchronous generator

PROTECTIVE DEVICES RESET

WICKET GATES CLOSED

WICKET GATES OPENPRESET POSITION

WATER LEVEL NORMAL

P.B AN

BUTTERFLY VALVE OPEN

WICKET GATE LOCK RELEASEDPRESSURE OIL SYSTEMS FUNCTIONAL

GENERATOR VOLTAGBUILDU

STOP SEQUENCE RESET

START SEQUENCE INITIATED

EXCITATION PRE-POSITION

AUXILIARY SYSTEM CHECKS

PRE START CHECKS

INITIAL EXCITATIONAPPLIE

UNIT ACCELERATES TONEAR SYNCHRONOUS SPEE

BRAKES RELEASED

GOVERNOR IN AUTOMATIC POSITION

___

GOVERNOR PRE POSITION

EXCIATION SYSTEMON VOLTAGEREGULATORCONTROL

___

ADJUSTREACTIVEOUTPU

GATELIMITRAISED

AN

ADJUST KILOWATTSOUTPUT

UNIRUNNINGCONTROL

VOLTAGFREQUENCYMATCHING

UNIT GENERATINGAS REQUIRED

GENERATORBREAKERCLOSE

GENERATOR BREAKER OPEN

IF PRES START CHECK (NORMAL

GENERATOR HEATERS OFF

P.B

SYNCHRONIZINGINITIATING

GENERATORSPINING

33kV

GENERATORBREAKER

L

AUXILIARY

4MW,6.6kV,0.9PFGENERATOR

TYPICAL SINGLE LINE DIAGRAM SHP (4 X 4MW)


Controlled action shut down shall be initiated by conditions shown in column -1 of Table -1 and shall perform actions shown in Column-2 of Table -1. Control action shut down for a typical 5 MW generating unit is shown in Fig. 5.

Table 1 : Controlled Action Shut Down

S. No.

Initiated by any of the following conditions

S. No

Perform following functions

1 Generator thrust bearing pads temperature very high

1

Trip generator breaker

2 Generator guide bearing pads temperature very high

2

Trip field breaker

3 Turbine guide bearing pads temperature very high

3

Initiates controlled action shut down and bring unit to stand still condition through governor action

4 Governor OPU oil level low stage-II 5 Governor OPU oil pressure low stage-II

Emergency shut down shall be initiated by conditions shown in column -1 of Table -2 and shall perform actions shown in Column-2 of Table -2. Emergency shut down for a typical 5 MW generating unit is shown in Fig. 6.

Table 2 : Emergency Shut Down Sl. No.


Sl. No


1 Speed 115% and deflector/ guide vanes/ runner blades apparatus not moved to closing

1 Trip generator breaker

2 Deflector etc. fails to close in preset time

2 Stop turbine by governor action

3 Unit over speed (electrical) > 140% 3 Trip generator field circuit breaker 4 Unit over speed (mechanical)>150% 4 Operate trip alarm in control room 5 Stop push button on control panel in

control room is pressed 5

Energizes emergency solenoid valve in governor cubicle to stop the turbine by bypassing governor

6 Close main inlet valve Electrical shut down shall be initiated by conditions shown in column -1 of Table -3 and shall perform actions shown in Column-2 of Table -3. Electrical shut down for a typical 5 MW generating unit is shown in Fig. 7.


Fig. 5 : Controlled Action Shut Down (Typical for gen. units above 5 MW)


Fig. 6 : Emergency Shut Down (Typical for Gen. Units above 5 MW)


Table 3 : Electrical Shut Down S. No.


S. No.


1 Over current in the excitation circuit 1 Trip generator breaker 2 Generator back up protection operates 2 Trip field breaker 3 Generator over voltage protection operates 3 Governor brings the unit to spin

at no load 4 Excitation failure protection operates5 Reverse power protection operates 6 Generator T/F IDMT over current, over

current instantaneous & earth fault protection operates

2.4 CONSIDERATIONS FOR SELECTING CONTROL SYSTEM

Governor and control systems for small hydro units especially in developing countries have to be selected keeping in view the following: (i) Traditional mechanical flow control governor with mechanical hydraulic devices is

complex demanding maintenance and high first cost. Further performance requirements of stability and sensitivity i.e. dead band, dead time and dashpot time especially for interconnected units may not be possible with mechanical governors.

(ii) The manpower as available for operation is unskilled and further adequate

supervision is not feasible. (iii) Load factors for stand-alone micro hydro are usually low which affects economic

viability. (iv) Cost of speed control and automation with electronic analog flow control

governors, unit control and plant control is high. These systems require attended operation and are mostly based on large capacity hydro units. This is making most of the units very costly and uneconomical to operate. Experience in successful operation of analog electronic control system in India for SHP is not good.

(v) Electronic digital flow control governors can take up plant control functions. (vi) Flow control turbine governors are expensive and not recommended for micro

hydro units. Electronic load control (ELC) governing system with water cooled hot water tanks as ballast loads for unit size up to 100 kW be used. If the thyristor control ELC is used then the generator be oversized up to 2% on kVA to cope with the higher circulating current. Accordingly, in case of micro hydrol units up to 100 kW size elimination of flow control governors by digital shunt load governor


(electronic load controllers) for economically viability and eliminating of continuous attendance is recommended.

(vii) Data storage function can be added to the digital governors. viii) Analog electronic governors and plant controllers are also used for small hydro auto

synchronizing and for remote control and monitoring of system. (x) Digital generation controllers were evolved to take care of speed control, unit

control and automation, unit protection and generation scheduling and have been successfully in operation for over ten years.

(xi) PLC based system are reliable and suitable for harsh conditions. These have been in

operation in India and abroad. (xii) Dedicated PC based systems for complete generation control can be easily adopted

for data acquisition and storage at low cost and can also be adapted to SCADA system. Customized software is used in these systems which inhibits wide spread use. Future systems using PC as controller and for SCADA with open architecture and use of commercially available software is recommended for economy and wide spread use.

Comparison of various options for for control system, including turbine governing

supervisory control and data acquisition are given in table-4.

2.5 CATEGORIZATION OF CONTROL SYSTEM As per Location:

a) Local b) Centralized c) Offsite

As per Mode of control:

a) Manual(Back up) b) Semi-Automatic(manual synchronizing) c) Automatic

As per supervision of operation:

a) Attended b) Unattended

Relationship of local centralized and off site control function is shown in fig-8.


Fig. 7 : Electrical Shut Down (Typical for Synchronizing Generator above 5 MW)


Fig. 8 : Typical Relationship of local centralized and off site control function

2.6 SYSTEM ARCHITECTURE, COMMUNICATION AND DATABASES

(i) Open architecture system should be followed in accordance with IEEE-1249-1996. Interface or operating standards for the following should comply with ISO/IEC 12119/IEEE 802.

Hardware interconnectivity Time stamping of data, Communications Operating system User Interface Data base

(ii) Each of these elements should be capable of being replaced by or communicate with system elements provided by other vendors.

(iii) The scope of the bidder should not be limited to the parts & components explicitly identified herein and shall have to provide any and all parts/components needed to meet the functional requirements laid down herein or are necessary for satisfactory operation of the plant.

2.7 CONTROL DATA NETWORKS Local area networks (LANs) should be configured to IEEE 802.3 (Ethernet) standard.

Commercially available software should be used as far as possible.

OFF SITE CONTROL

CENTRALISED CONTROL

UNIT 1 LOCAL

CONTROL

UNIT 2 LOCAL

CONTROL

AUXULARY CONTROL

SWITCHYARD CONTROL

Communication Link

Remote from controlled equipment but with in plant


Table 4 : Comparison of various options for control system, including turbine governing supervisory control and data acquisition

S. No.

Turbine Gov. and Controller Type

Unit size kW

Mode of operation

Suitability Cost including Gov. control, protection, SCADA data Aq., Storage and Retrieval (see note-1)

Recommendation Remarks

Turbine Gov.

Unit control

Unit Prot.

Data storage and Retrieval

SCADA

Capital O & M

1. Mech. Flow control Gov. 50-100 Iso. At high extra cost Very high High without SCADA

Not recommendation

Grid 100-500 & above

Iso.

Grid

2. Load control governor 50-100 Iso. Suitable At extra cost Low Low Not considered Digital load control governor may be developed for SCADA

Grid

Do not available

100-500

Iso. See note 3

Grid

Not feasible

3. Analogue, Electronic Gov. & Plant Controller

50-100 Iso. Suitable At high extra cost Very high cost Not recommended

Grid Above 100 Iso. High Moderate

to high Grid

4. PLC integrated controller with SCADA by PC

SHP 100 kW to 5 MW

Iso. Suitable Low Moderate Recommended

Grid

5. PLC digital governor with plant controller and SCADA with redundant PC

Above 5 MW

Iso. Suitable See note 2

High Moderate Recommended for units above 5 MW

Grid

6. Data Logger with ELC load controller

5 to 100 kW Iso. Data not available Low Moderate Recommended Grid

7. PC based integrated system for governing; plant control protection and metering

100 kW to 2500 kW

Iso. Suitable – Indigenous system not available Low Medium Recommended with high speed PC suitable for harsh area

Grid

Notes: 1. Cost normalized with main and backup SCADA system. 2. Dedicated digital controller for Gov. and plant control with PC based SCADA backup. 3. Recommended in conjunction with partial water flow control


2.8 HUMAN-MACHINE INTERFACE (HMI)

The operator’s station of the station controller (SCADA system) should have an elaborate and friendly man-machine interface. A 45.6 mm (19”) or larger monitor should be provided for the display.. The screen displays should be suitably designed to provide information in most appropriate forms such as text, tables, curves, bar charts, dynamic mimic diagrams, graphic symbols, all in colour. An event printer should be connected to PC of the SCADA system. Events should be printed out spontaneously as they arrive. Provision should be made to connect and use another printer simultaneously. Touch control screen, voice and other advanced modes of HMI are desired and should be preferred. The entire customization of software for HMI and report generation should be carried out. A window based operating system should be preferred.

2.9 HARDWARE Input/output system should have following capabilities. (i). Portability and the exchange of I/O cards from one I/O location to another. This

can reduce spare parts requirements. (ii). Availability of I/O cards to be replaced under power. This avoids the need to

shutdown an entire I/O location to change one card. (iii). Sequence-of-Events (SOE) time tagging at the I/O locations; accuracy and

resolution. (iv). Availability of I/O signal types and levels that support the field device signals to

be used. (v). Support of redundant field devices, capability for redundant I/O from field device

to the database and operator interface. (vi). I/O diagnostics available at the card, e.g., card failure indicating LEDs, or through

software in the system.

2.10 GROUNDING Each equipment rack in which automation system components are located should be

separately connected to the powerhouse ground mat by a large gauge wire.

Shielded cables should be used for analog signals between the transducers and the automation system. Each shield should be tied to the signal common potential at the transducer end of the cable. If there are terminations or junction boxes between the transducers and automation system, each shield circuit should be maintained as a separate continuous circuit through such junction or termination boxes.

2.11 STATIC CONTROL Equipment should be immune to static problems in the normal operating configuration.

Anti-static carpet and proper grounding for all devices that an operator may contact should be provided.


2.12 INFORMATION AND CONTROL SIGNALS Information and control signal for proper control and monitoring will be acquired from

the main and auxiliary/associated equipment and shall be provided as tentatively detailed along with the equipment as out lined in this paragraph. Deviation will be intimated in the bid 25% spare capacity for inputs and output shall be provided.

The control system shall receive input signals from main equipment such as the turbine or

the generator, and from various other accessory equipments, such as the governor, exciter, and automatic synchronizer. Status inputs shall be obtained from control switches, level and function switches indicative of pressure, position etc, throughout the plant. The proper combination of these inputs to the control system logic will provide outputs to the governor, the exciter, and other equipment to start or shutdown the unit. Any abnormalities in the inputs must prevent the unit’s startup, or if already on-line, provide an alarm or initiate its shutdown. Input signals from following main equipment are required: (i). Generator (ii). Generator field excitation equipment (iii). Generator terminal equipment (Line and Neutral side) (iv). Unit generator breaker equipment (v). Turbine (vi). Governor (vii). Generator cooling (viii). Service air(above 5MW) (ix). Cooling water(above 5MW) (x). DC power supply (xi). AC auxiliary power supply (xii). Water level monitoring (xiii). Fire protection

Following four types of signals are provided between control board and particular equipment:

(i). Analog inputs for variable signals from CTs, VTs, RTDs, pressure, flow, level, vibration etc.

(ii). Digital inputs provides digitalized values of variable quantities from the equipment

(iii). Digital outputs – command signals from control boards to equipment (iv). Analog outputs – transmit variable signals from control to equipment e.g.

governor, voltage regulator etc.


2.13 COMMUNICATION LINKS 2.13.1 Communication links with remote offsite control

Following methods are available for implementing control from a remote location:

(i). Hardwired communication circuits (telephone type line, optical cables etc.) (ii). Leased telephone lines (iii). Power line carries communication system (iv). Microwave communication system

Metallic circuit in hardwired communication circuits and leased telephone lines, requires special protection for equipments and personals against ground potential rise (GPR) due to electric system fault, since the hydro-generator is source of fault current. GPR is also caused by lightning transmitted through power lines entering the power plant. As such suitable mitigation has to be provided. Power line carrier including insulated ground wire system can be used for communications purposes. This method couples a high frequency signal on the power line or insulated ground wire and is decoupled at an offsite point.

2.13.2 Communication link between control board and equipment:

Data and control signals will be required to be transmitted. The communication link between control board and equipment should be reliable. Optical fiber cable, shielded cable are various options. Communication links required are given in table 5:

Table 5 : Communication Links

Communication Links Between control board & Main equipments.

Between control board &Auxiliary equipments

S. No. Equipment S. No. Equipment 1. Generator neutral and terminal

equipment 1. Fire protection

2. Head water and tail water level

equipment 2. AC Power supply

3. Water passage shut off or bye

pass valves gates etc. 3. DC Power supply

4. Turbine 4. Service water 5. Unit transformer 5. Service air 6. Circuits breaker and switches 6. Water level monitoring 7. Generator 7. Turbine flow monitoring 8. Intake gates or main inlet valve

and draft tube gates

9. Turbine governing system 10. Generator excitation system


2.14 CONTROL SYSTEMS FOR VARIOUS CATEGORIES OF SHP 2.14.1 Control for micro hydro power plant (Up to 100 kW)

Recommendations of “Micro Hydro Quality Standards prepared by AHEC, IIT, Roorkee” in Sept. 2005 be referred which are reproduced as in table 6.

Table 6 : Micro Hydro Quality Standards

Description Category (Installed Capacity in KW) Category A

(Up to 10 kW) Category B

(Above 10 kW and up to 50 kW)

Category C (Above 50 kW and up to 100

kW) Control, Switchgear and Metering

Controller (Preferable –Micro processor based)

Electronic load controller (ELC) or Induction generator Controller (IGC)

(ELC) Electronic load controller preferred or (IGC) Induction generator Controller

Electronic load controller (ELC) or Flow control Governor

Ballast Load of ELC

Air heater Water heater Water heater

2.14.2 Control for Small Hydro Power Plants (Above 100 kW and up to 5000 kW) 2.14.2.1 Integrated Governor and Plant Control System

Following computer based systems have been installed in the country. (i). Microprocessor based controllers with specially developed software (ii). PLC based controllers (iii). PC based controllers

Present and recommend modern practice is to have PLC based automatic control system with manual control as backup. A common PC for Supervisory Control and data Acquisition system (SCADA) may be provided. Redundant PLC for automation as backup is not provided. Microprocessor controller (PLC/PC) is used to provide following unit and plant control functions. (i) Turbine Governing control & Monitoring (ii) Generator control & Monitoring (iii) Starting sequence control (iv) Auto synchronizing (if required) (v) Automatic shut down control (vi) Emergency shut down (vii) Control of turbine generator auxiliaries (viii) Monitoring of turbine generator auxiliaries


A dedicated controller for normal operation in isolated/interconnected operation is required. This controller can perform all the control functions of unit control e.g. starting sequence control, auxiliary control, emergency and normal shut down and governing. In manual/maintenance control mode the control system controller can perform the following control functions.

(i) Manual turbine gate or needle valve control (ii) Manual synchronization control (iii) Manual circuit breaker control (iv) Manual load control (v) Manual brake control (vi) Manual normal shut down control (vii) Automatic emergency shut down

In addition the control system can monitor all critical items that are require for safe operation.

(i) Protective relay status (ii) Generator breaker status (iii) Lock out relay status (iv) Hydraulic oil high/low pressure/level (v) Speed increaser, high oil temperature/level/flow (vi) Brake status (vii) Generator/bearing temperature (viii) Head water/tail water level (ix) Generator current, voltage, power-factor, kW, kVAR & kWh (x) System voltage and frequency

Analogue meters may be provided as back up.

2.14.2.2 Computer (PLC) based control system for SHP up to 5 MW

Most small hydro powerhouses in the range have the control room at the same level as the machine hall. The hard wired manual unit control and computer based (PLC) automatic control system is provided in the control room. Supervisory control and data acquisition system (SCADA) if required is provided by a common Personnel Computer for all the units for Supervisory/Remote control functions in the control room.

2.14.2.3 Typical example of Computer (PLC) based control system for SHP (101 kW to 5000 kW) in the Country

The hard wired manual unit control and computer based (PLC) automatic control system is provided in the control room.


Supervisory control and data acquisition system (SACADA) if required is provided by a common Personnel Computer for all the units for Supervisory/Remote control functions in the control room for which one additional panel or desk is provided.

(i) SHP up to and below 1000 kW

World Bank, 1991 recommendation for control of irrigation based SHP in this range by a PLC based unit controller for the powerhouse with a common PC for SCADA and offsite control provision for all units in this range.

PLC integrated unit controller with PC for supervisory control data acquisition and remote control facilities for canal fall SHPs with provision for remote control of three nearby canal fall power plants is shown in Fig.-9.

(ii) SHP - 2 x 3.5 MW Single line diagram is at figure-10; PLC integrated control unit control & protection panels are shown in figure-11 & 12. SCADA is by a common PC.

(iii) SHP – 4 x 4 MW Control system unit control (manual/automatic) is from Turbine Auxiliary Governor Panel (TAGP) along with Manual and Protection panel in control room as shown in Figure-13.

2.14.3Control for small hydro power station (above 5000 kW)- (Distributed computer

control) 2.14.3.1 Introduction

Modern control system employed for power stations having capacity above 5 MW is distributed computer control system with adequate redundancy as generally shown in fig-14. Provision for hard wired manual control and modern for offsite control is also shown in figure. Main controllers that is turbine governor and excitation control are controlled by their own microprocessor controllers (PLC based). The digital modules used in the controller should belong to the same family hardware which is also being used in unit control panels. Software used in the governors generally includes PID/temporary droop control scheme for regulation; Start up and shutdown logic etc. Similarly excitation system controls are microprocessor PLC based. Function block programming language to be used should be same as in unit control panels.

2.14.3.2 Functional Capabilities

Functional capabilities generally provided are summarized below:

(i) Computer based automation system should permit operation of power plant, switchyard, outlet works, Inlet valves etc. from a single control point (centralised control room).


(ii) Local control may be provided by equipment preferably located near the generating unit. The local unit computer should be part of the equipment.

(iii) Automatic unit start/stop control sequencing is part of computer based automation. Automation system should include capability to provide diagnostic information so as to isolate the problem and get the unit on line as fast as possible.

(iv) Auto synchronizing is computer based. There is no objection to provide synchronizing function as internal to the automation system. Check synchronizing relay is provided for security.

(v) The computer system should optimize individual unit turbine operation to enhance unit operation in respect of following:

(a) Efficiency maximization - gate position, flow, unit kW output, unit reactive power output.

(b) Minimization unit vibration or rough running zone - gate position, unit vibration.

(c) Minimization of cavitation: Adjust Gate position, flow, and Hydraulic head as per turbine manufacturers’ cavitation curve.

(d) Black start control - This may include starting the unit in emergency.

(vi) Centralised Control – Individual units, switchyard, station service control, plant voltage/VAR control, water and power optimization; Fore bay level control.

(vii) Provide Data acquisition capabilities (viii) Provide Alarm processing and diagnostics (ix) Provide Report generation (x) Provide Maintenance and management interface (xi) Provide Data acquisition and retrieval (xii) Provide Data access (xiii) Provide Operator simulation training (xiv) Provision of operation in stand alone or in an isolated island by frequency relays

The recommended control system is shown in Fig-15. Manual control facility is provided on PLC panel if in control room or by or special panel as shown in the figure 14 and Figure 15. A typical block diagram of computer based control system for a 2 x 10 MVA power house with offsite control is shown in Fig. 15. A provision for a programming station with back up for operation is also included as redundant system. Main controllers that is turbine governor (PLC based) and excitation control are controlled by their own microprocessor controllers. The digital modules used in the controller belong to the same family hardware which is also being used in unit control panels. Software used in the governors generally includes PID/temporary droop control scheme for regulation; Start up and shutdown logic etc. Similarly excitation system controls are microprocessor based. Function block programming language to be used should be same as in unit control panels.


(i). Each of these elements should be capable of being replaced by or communicate with system elements provided by other vendors.

(ii). Distributed control system is used (iii). Adequate redundancy is provided

2.14.3.3 Description

The control system is built up of independent control modules in hierarchical control levels. The overall control is affected from the Operator Work Stations. The operator console assist the operator for an easy operation of power station. It also allows to print out and show on the video displays all relevant signals, events, alarms, status, status change, abnormalities, history data and plant conditions on request or immediately in case of alarm. The data is stored on hard disk. The operator console is connected to next level, namely the control boards, through a local network. Basic manual control of drives is made possible from control boards. The local starter panels can be used in case of failure of control boards or for test and maintenance purposes. The control system should be suitable for manual and automatic start-up, running & shut-down of the generating units and the station auxiliary systems. The control should be accomplished by master control or step sequence systems to be realized using Distributed Processing Units DPUs).

In the system each unit is controlled by a unit control board for automatic start-stop sequence. In the automatic mode the unit is started and stopped by computer control or by push buttons which actuates the complete sequence with all interlocks while in the manual mode only the plant safety requirements is actuated. The unit control should be responsible for the overall sequence of operation, for example when the machine is started or shutdown, it takes the process criteria as its input and execute a sequence program and issues commands to the drive control. It checks for the presence of all the required criteria before it issues a particular command. Also time taken for the execution of the command is monitored and an alarm or trip is generated if command execution takes more than stipulated time. (i) Functional Group and Drive Control Control of all auxiliaries and drives pertaining to the unit is carried out. It is possible to control either by the commands received by the sequence control or commands from push buttons mounted on the panel. All required logic and interlocks for each drive should be built up by software logic in the system.


Fig. 9 : Typical System Configuration Canal SHP project (Punjab)


Fig. 10 : Typical Single Line Diagram for 2 x 3.5 MW SHP

HV CIRCUIT BREAKER

LEGEND

NOMENCLATURE

LINK

LIGHTNING ARRESTOR

41G

POTENTIAL TRANSFORMER

40 -------- LOSS OF EXCITATION RELAY

FUSE

CURRENT TRANSFORMER

TRANSFORMER

EARTH

ISOLATING SWITCH

EXCITATION BREAKER WITHDISCHARGE RESISTOR

52-3

33 kV BUS

11 KV BREAKER

DISTRIBUTIONTRANSFORMER

CT 77.5/.578A

CT 775/1A

G1

PS

3500 kW 0.8 PF 3.3 kVGENERATOR-1

52-1

5000 kVA, 3.3/33 kVGENERATORTRANSFORMER-1

11-1

P.T.

41G

41G -------- EXCITATION BREAKER

45G -------- FIELD SURGE PROTECTION51 -------- OVER CURRENT RELAY

51V -------- OVER CURRENT VOLTAGE RESTRAINT RELAY51D -------- DIRECTIONAL OVER CURRENT RELAYE/F -------- EARTH FAULT RELAY59 -------- OVER VOLTAGE RELAY63 -------- BUCHHOLZ RELAY

64F -------- ROTOR EARTH FAULT RELAY64G -------- STATOR EARTH FAULT RELAY64T -------- BACKUP POWER SYSTEM E/F RELAY

87G -------- GENERATOR EARTH FAULT RELAY87GT -------- GEN. TRANSFORMER E/F RELAY

25 -------- CHECK SYNCHRONISING46 -------- NEGATIVE SEQUENCE RELAY

PS

CT 775/5A

CT 775/5A5P10

CT 775/5A

CT 775/5A

AVR

M

CT 250/125/1ACORE-1, 5P10

P.T.

64T

CT 75/1A, 5P10

RECTIFIERBRIDGE

RECTIFIERTRANSFORMER

3.3 KV CUBICLE

CORE-2, METERINGCT 250/125/1A

TO 33 kV SUBSTATION (APPROX. 30 kmGARIYABAND S/S)

// //3

33kV / 110V

/3

/

33kV

/33

110V///

/

52-6

ACC.CLASS 1-0

L.A.

87GT51

87GT

50/5A

CT 250/125/1ACORE-1, 5P10

L.A.

CT 250/125/1A

52-5

ACC.CLASS 1-0CORE-2, METERING

TO 33 kV SUBSTATION (APPROX. 30 kmGARIYABAND S/S)


G23500 kW 0.8 PF 3.3 kVGENERATOR-2

52-2

11-2

P.T.

P.T.

45G

5P10

PS

PSCT 775/1A

CT 775/5A

CT 775/5A

CT 77.5/.578A

AVR

M

CT 775/5A


RECTIFIERBRIDGE

64T

CT 75/1A, 5P10

5000 kVA 3.3/33, kVGENERATORTRANSFORMER-1

CT 775/5A

3.3 KV CUBICLE

41G

87GT51

87GT

50/5A


Fig. 11 : Typical PLC Controller with PC SCADA (Control & Protection System) for a (2 x 3.5 MW)

DC

PO

WE

R S

UP

PL

Y

CP

U

DIGITAL INPUT

DC

PO

WE

R S

UP

PL

Y

DIG

ITA

L I

NP

UT

DIGITAL OUTPUT

AN

AL

OG

IN

PU

T

AN

AL

OG

IN

PU

TA

NA

LO

G M

IXE

DM

OD

UL

E

SPARE

RK2

10 POINT I/O RACK 10 POINT I/O RACK

MMI

RK1

SCADA

DC

PO

WE

R S

UP

PL

Y

CP

U

DIGITAL INPUT

DC

PO

WE

R S

UP

PL

Y

DIG

ITA

L I

NP

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DIGITAL OUTPUT

AN

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IN

PU

T

AN

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IN

PU

TA

NA

LO

G M

IXE

DM

OD

UL

E

SPARE

RK2

10 POINT I/O RACK 10 POINT I/O RACK

MMI

RK1

DF1 (COM1) DF1 (COM2)

SIGNALCONVERTOR

MULTI FUCNTIONTRANSDUCER-1


SYSTEM-1



SYSTEM-2

TEMPERATURERECORDERS-1

SYSTEM-1 SYSTEM-2




UNIT-1 UNIT-2

MODBUS (COM3)

CPU -CENTRAL PROCESSING UNIT

(PC BASED)


Fig. 12 : Typical General Arrangement of Control & Protection


Fig. 13 : Typical Control and Protection of a SHP (4 x 4 MW)


Fig. 14 : Typical Configuration for Computerized Hydro Station (above 5 MW)


Fig. 15 : Typical HMI System for a 2 unit Computerized Station with offsite Control


(ii) Sequence Control Master/Stepped sequence control performs the functions of sequential start up, shut down and / or changeover of the status of the machine. The status of unit is stand still, shut down, spin and generate. Master control type control is preferred. (iii) Automatic Mode In the automatic mode the operator gives the command only once to start the program. No further intervention is needed for normal execution. Normally the unit is operated in this mode. At each step, specified process criteria is to be checked and the program continues if the criteria is satisfied. A time monitoring of each step execution is provided and if this time is exceeded, the program stops and display the missing criteria. During the program execution if any protection operates, program execution stops and the machine brought to shut down. (iv) Step by Step Mode This mode is used to execute the program in steps. Every time a step is ready to be executed, the operator initiates the step through a push button command. This mode is used during commissioning and test phases. All indications of the sequence control and display of missing criteria is available in this mode. If timing of the step exceeds the set time, execution is blocked. On completion of each step, an indication for the readiness to execute the next step is available. The commands to functional group and drive control is issued during execution of the relevant steps. The drive control is also possible by operating push button command in this mode of operation.

2.14.3.4 Common Control Board

A common control board for the control & monitoring of common station auxiliaries, Feeders and Bus coupler is also required to be provided. The panel may consist of the required number of switches, ILPBS, relays, indicating meters etc. as required. Following synchronizing equipments are generally provided on the Common Control Board. (i). A dual channel auto synchronizer with voltage and frequency matching units which

issues voltage adjustment and speed adjustment commands and releases breaker closing command when the frequency, voltage and phase of the generate and grid are matched within limits.

(ii). Manual synchronizing equipment consisting of synchroscope, voltmeter and frequency meters for incoming and running bus and a check synchronizing relay is also provided.


2.14.3.5 Engineering Work Station (Programming & Training Console)

The programming tool included in the Engineering Station is used for accessing & modifying logic programs of the processor modules, reading the status of binary & analog signals with their addresses, simulating signals to the processor.

2.14.3.6 24 V Battery and Battery Charger

Two numbers battery chargers, common battery bank and direct current distribution boards (DCDB) are provided for the stabilized power supply requirement of electronic panels of control boards. Lead acid / Nickel Cadmium batteries of sufficient capacity should be provided. The battery charger should be provided with its associated float and boost charger. For small power station where one battery set is selected the charger should have provision of redundant float charger. For power station where two battery sets and two chargers have been selected, interchangeability of chargers should be ensured. Two no. UPS system having common battery and common AC Distribution Board & manual by-pass are provided for giving regulated Uninterrupted Power Supply to SCADA. The system should be solid state type with silicon controlled rectifiers to convert mains input to DC for charging the battery. The UPS works on a 1-phase 230 volts supply.

2.14.3.8 Supervisory Control and Data Acquisition (SCADA) – Functions

Supervisory control and data acquisition system for control and monitoring of the plant should be provided using Man Machine Interface (MMI) & (Data Acquisition System) DAS computers. The system is intended to meet total operating functions of the plant, which are normally performed by plant operators. The SCADA system should be complete with all primary sensors, cables, analyzers/ transmitters, monitors, system hardware/ software and peripherals etc. to monitor/ control the parameters for control, protection, annunciation, event recording for different equipments including. List of essential sensors and type of sensors are given in the following table 7:

Table 7 : List of Sensors

A.Generator Type of Sensors Generator stator winding temperature

Resistance type temperature detectors (RTD) PT 100 type

Thrust and guide bearing temperature

Resistance temperature detectors (RTDs) Embedded in walls, shoes of thrust bearing and in each segment of guide bearing

Bearing oil temperature Temperature detectors in each separate bearing oil reservoir


Bearing oil level high/low Sensors for each oil reservoir high/low Cooling air each cooler Temperature detector at inlet and outlet Rotor temperature Temperature monitoring system for continuous monitoring field

temperature Fire detection & protection system

Sensors as required are provided for detection and fire fighting

Thrust bearing high pressure oil system start/stop interlock

Pressure switches

Brake position As per IEEE 1010-2006 Electrical measurements and protection

Microprocessor based transducer for interface with CTs & PTs

B.Excitation Type of Sensors Static excitation system Generally in accordance with IEEE 1010-2006 C.Turbine Type of Sensors Turbine guide bearing temperature in each segment

RTD for indication and recorder TSD Thermo signaling device for alarm & trip

Turbine guide bearing oil temperature

RTD for indication & alarm

Oil pressure in accumulator Level switch Turbine guide bearing level High/low

Level switch

Other sensors as considered necessary for the unit

As per IEEE 1010-2006

D.Governor Type of Sensors Speed indication Synchronous speed, under speed & over speed

Electrically actuated speed relays by comparing the speed signal to reference signal

Centrifugal device mounted on the turbine shaft to mechanically actuate over speed switch

Wicket gate position indication/ position switches for control & indication


Governor oil pressure unit switches for oil level/pressure and sump oil temperature


Governor power supply failure, As per IEEE 1010-2006 E. Generator Transformer. Transducers as required F. High Voltage Circuit Breaker Transducers as required G. Instrument Transformers Transducers as required H. Auxiliary System Transducers as required

Overall philosophy of control and monitoring of the plant may be as follows: Without SCADA: All Control functions for the generating units are through the electronic panels of control boards, with the associated interlocks, sequential operation and protection trip functions being met by the software programs in the processor


modules. Overall monitoring may be through the indications, meters and annunciation features provided on the control boards. Station operators may take care of the data logging.

With SCADA: In this mode, each and every control functions provided on Unit Control Panel and Line control panel is through the HMI of SCADA system. Further, the joint control of units for overall control of active, reactive power and voltage is carried out from HMI of SCADA. Commands from SCADA is dispatched to respective unit control boards through Ethernet bus. Further, processing of commands is done by the DPUs of unit control panels through their software logic.

Automatic logging of periodical logs, event logs and alarm summaries may be achieved in the SCADA system along with overall plant monitoring through data acquisition in the form of alarms, mimics, trends, bar charts etc. Total plant operation, monitoring, logging etc. should be possible from SCADA without any need of attendance elsewhere in the plant.

2.14.3.9 Grounding System and Static Control

A separate grounding system should be provided for the plant and static control as generally shown in figure-16.

2.14.3.10 Testing Factory Assembly and Test, Field Test should be performed as given in the typical specifications. A training programme for the operators and maintenance personnel should be included in the procurement specifications.

2.15 RECOMMENDATION FOR AUTOMATION AND CONTROL

Recommendations are as shown in table 8 below:

Table 8 : Recommendations for automation and control

Description Installed Capacity in kW

Unit capacity up to 100 kW

Unit capacity above 100 kW and up to 5000

kW

Unit capacity above 5000 kW

Preferred Control System

ELC controller ( Data logger optional) Suitable for isolated and grid connected operation

Integrated generator and plant control system for governing; plant control protection and metering SCADA system optional.

Distributed computer control System, Digital governor with unit controller, plant controller, auxiliary controller, switch yard controller and SCADA with redundant PC


Fig. 16: Typical Computerized Control & Monitoring System - Grounding Scheme


SECTION-III PROTECTION AND RELAYING

3.1 GENERAL

Small hydro turbine-generators should be protected against mechanical, electrical, hydraulic and thermal damage that may occur as a result of abnormal conditions in the plant or in the utility system to which the plant is electrically connected. The abnormal operating conditions that may arise should be detected automatically and corrective action taken in a timely fashion to minimize the impact. Relays (utilizing electrical quantities), temperature sensors, pressure or liquid level sensors, and mechanical contacts operated by centrifugal force, etc., may be utilized in the detection of abnormal conditions. These devices in turn operate other electrical and mechanical devices to isolate the equipment from the system. Where programmable controllers are provided for unit control, they can also perform mechanical protection including hydraulic and thermal protection. Operating problems with the turbine, generator, or associated auxiliary equipment require an orderly shutdown of the affected unit while the remaining generating units (if more than one is in the plant) continue to operate. Alarm indicators could be used to advise operating personnel of the changed operating conditions. Loss of individual items of auxiliary equipment may or may not be critical to the overall operation of the small plant, depending upon the extent of redundancy provided in the auxiliary systems. Many auxiliary equipment problems may necessitate loss of generation until the abnormal conditions has been determined and corrected by operating or maintenance staff. The type and extent of the protection provided will depend upon many considerations, some of which are: (i) The capacity, number, and type of units in the plant; (ii) The type of power system; (iii) Inter connecting grid requirements; (iv) The owner’s dependence on the plant for power; (v) Manufacturer’s recommendations; (vi) Equipment capabilities; and (vii) Control location and extent of monitoring. Overall, though, the design of the protective systems and equipment is intended to detect abnormal conditions quickly and isolate the affected equipment as rapidly as possible, so as to minimize the extent of damage and yet retain the maximum amount of equipment in service.


Small hydroelectric power plants generally contain less complex systems than large stations, and therefore tend to require less protective equipment. On the other hand, the very small stations may be unattended and under automatic control, and frequently have little control and data monitoring at an off-site location. This greater isolation tends to increase the protection demands of the smaller plants. An inherent part of the power plant protection is the design of the automatic controls to recognize and act on abnormal conditions or control failures during startup. Close coordination of the unit controls and other protection is essential.

3.2 ABNORMAL CONDITIONS

Abnormal conditions of electromechanical equipments are given in table 9, 10 and 11

Table 9 : Abnormal Conditions of Mechanical Equipment of plant

Turbines

Hydraulic Control System

Water Passage Equipment

S. No.

Abnormal Conditions

S. No.

Abnormal Conditions S. No.

Abnormal Conditions

1

Excessive vibration(above 10MW)

1

Low accumulator oil level

1

Failure of head gate or inlet valve

2 Bearing problems 2 Low accumulator pressure 2 Head gate inoperative 3

Over speed

3

Electrical, electronic, hydraulic malfunction within the governing or gate positioning system

3

Trash rack blockage

4 Insufficient water flow

4 Water level control malfunction

5 Shear pin failure 6 Grease system failure

Table 10 : Abnormal Conditions of Electrical Equipment of plant

Generator Gen. Transformer Gen. Switchgear and Bus

S. No.

Abnormal Conditions

S. No.

Abnormal Conditions

S. No.

Abnormal Conditions

1. Abnormal electrical conditions 1.

Electrical fault

1.

Electrical fault

2.

Stator winding high temperature

2.

High temperature

2.

Mechanical failure

3. Low frequency 3. Abnormal oil level 3. Loss of control power


4. Bearing problems 4. Fire

5. Motoring 6. Fire 7. Excessive vibration 8. Cooling failure 9. Over speed

Table 11 : Abnormal conditions of Auxiliaries and grid

Auxiliaries Grid System S. No.

Abnormal Conditions S. No.

Abnormal Conditions

1 Aux.Transformer failure 1 Ground or phase faults 2 DC System Trouble 2 Single phasing 3 Station Air System Problem 3 Abnormal voltage 4 Cooling Water System Problem 4 System separation (islanding) 5 Flooding 6 Fire 7

Water level Monitoring System Malfunction

8

Protection or Control Logic System Malfunction

3.3 DEVICES USED IN A TYPICAL PROTECTION SYSTEM

There are numerous ways of providing the functional protective requirements of the plant. While standard devices are generally available that can provide the protective functions required, however each station should have specific design suitable for protection requirements of the power plant equipment as well as the interconnection. Protective devices which are normally used are given in table 12:

Table 12 : Protective Devices

S. No.

Item Devices

1. Temperature

A temperature device, incorporating display and contacts for alarm, annunciation and tripping to monitor bearing, stator and transformer winding temperatures. Resistance temperature devices operating relays can also be used to detect generator stator overheating.

2. Pressure and Level

Pressure and level switches installed in the turbine air, and oil systems, to alarm, block startup, or trip, as necessary.

3. Over and under speed

Direct-connected or electrically driven speed switches for alarm, control, and tripping.

4. Vibration Vibration detectors monitoring turbine or generator shaft sections,


with alarm and trip contacts. 5. Water level

A measuring system incorporating level sensors and monitoring equipment, to alarm, trip, or control turbine output on limiting values of headwater or tail water level, or head

6. Fire

Sensors located in areas where fire can occur and connected to a central fire monitor for alarm. Small generators usually do not have fire sensors or suppression equipment, since they are not usually enclosed.

7. Miscellaneous mechanical system

Sensing devices are integral to the protected systems, such as automatic greasing system, wicket gate shear pins, cooling water system and drainage system.

3.3.2 Protective Relay and Protection System 3.3.2.1 Features of relays

The protective relays stand watch and in the event of failures short circuits or abnormal operating conditions help de-energize the unhealthy section of power system and restrain interference with rest of it and limit damage to equipment and ensure safety of personnel. The essential features of protective relays are shown in table 13.

Table 13 : Features of relays

S. No.

Feature Purpose

i. Reliability To ensure correct action even after long period of inactivity and also to offer repeated operation under sever condition

ii. Selectivity To ensure that only the unhealthy part of system is disconnected iii. Sensitivity Detection of short circuit or abnormal operating condition iv. Speed To prevent and minimize damage and risk to instability of

rotating plant. v. Stability The ability to operate only under those conditions that calls for its

operation and to remain either passive or biased against operation under all other conditions.

3.3.2.2 Protective Relay Technology

Protective relay technology has changed significantly in recent years. Induction disk relays for each individual protective function were normally used. Individual solid state static relays for protective function were introduced in the decade 1980 – 1990 and IS: 3231 – 1965 was accordingly revised in 1987. The old conventional electromagnetic relays were replaced with static relays which are much faster and maintenance free. These relays are more reliable and sensitive. These days microprocessor based multifunction relays are available which have different protections elements and therefore, a separate relay for each protection is not required.


3.3.2.3 Isolation of Digital Control and Protection System

Solid state digital control and protection system is fast replacing hard wired control and electro-mechanical relaying systems in hydro stations. These systems working on 4 to 5 volts with respect to ground are susceptible to damage/malfunction from induced voltage from switching surges, rise of ground grid voltage on ground faults and lightning surges etc. Computer control (SCADA)/protection system receive signals from equipment to be controlled and give output signals to actuators for control/protection action. Isolation of the digital system for protection and control is very important to avoid damage. A design that provide complete isolation from the high frequency surges is vital to maximize plants on line availability. Standards addressing these problems for the control and protection equipment have been issued by IEC and other standards organization which can be referred Programmable logic controller (PLC) input/output racks used in hydro plants are suitable for use in harsh environment of the hydro plants. PLCs input/output racks and solid state components are designed to withstand the surges. Isolation is by optical coupling I/O racks and cards so as to provide isolation and withstand surge voltage capability. There are many standards for surge protection, grounding and acceptable installation procedures which can be referred.

3.3.2.3.1 Main advantages and disadvantages for application of digital protection in hydroelectric station

(i). Control Power: The operating energy for most electromechanical relays is

obtained from the measured currents and/or voltages, but most microprocessor relays require a source of control power.

(ii). Multi Protective Functions: Digital relays provide multiple protective functions in one relay. In contrast, older relay system required an individual relay for each protective function. Consequently, multifunction digital relays reduce panel space and wiring costs while providing equivalent protection. Multifunction feature can result in a loss of redundancy. For instance, the failure of a single-phase over current relay is backed up by the remaining phase and neutral relays. In a microprocessor scheme, the phase and neutral elements are frequently combined in one package and a single failure can disable the protection.

(iii). Self Monitoring: microprocessor-based digital relays have “watchdog timers” to monitor their own operating status on a continual basis. Any potential malfunction will be indentified and communicated to the control system. The self monitoring feature eliminates the possibility of a non functioning relay in the plant protective relay system. In previous protective relay systems, a non functional induction disk


or solid state relay would not normally be discovered until the next maintenance test of the protective relay system.

The self-monitoring capability of these relays is only effective if the alarm output can be communicated to a manned location such as a control room. Also, the remote communication ability assumes there is a communication channel available to the relay.

(iv). Communication: The digital relay uses a digital communication scheme which allows the relay to communicate directly with the plant control system. The digital relays are provided with serial data ports based on established protocols, which should be compatible with the DCS (Distributed Computer System)/PLC communication protocol used at the plant.

The communication capability of microprocessor relays in hydroelectric stations

interconnection with grid can benefit both the power plant operating and power receiving grid authority from the communication capability. In particular, the recorded history of events can be very useful in analyzing relay operations after a fault. However, for both to communicate directly with the relay will require special considerations. Both the SHP owner and grid authority may be required to purchase software license for the communication software if that software is propriety nature. Also, they will both need to maintain the same versions of the software. The communication settings, such as modem baud rate, will have to be mutually agreed on. Some relays have security passwords, which restrict access. There may be one password to permit read only access to meter and event records and a different password to make changes. Although both parties may have read only access, ideally only one party should have the necessary access to make setting changes.

(v). Self Calibration: Digital relays are provided with a self-calibration routine, which can be initiated by selecting the relay calibration mode in the relay’s soft ware programming.

(vi). Programmable Set points: Previous relay systems required “experienced” protective relay engineers to calculate the set points for each individual relay, define the zones of protection for each primary and back-up relay, and perform a coordination analysis to confirm that the operation times of the various protective relays did not conflict. The digital relay uses a Disc Operating System (DOS) software program which provides detailed instructions and recommended set points for each protective relay function based upon system characteristics.

(vii). Event Storage: The digital relays can store selected wave forms on an oscillograph record. The number of cycles that can be stored differ with the manufacturer. This record will show the condition of each of the selected waveforms before and after the protective relay has operated. This additional information is valuable in determining the cause of the protective relay trip.

(viii). Other Considerations (a) Microprocessor transformer package that has both differential and over current

relaying provide less redundancy than a scheme comprising separate relays. The


self-diagnostics ability of the microprocessor relay, and its ability to communicate failure alarms, mitigates some of the loss of redundancy. It may also be economical to use multiple microprocessor relay.

(b) Microprocessor relays require more engineering in the application and setting of the relay though less work in the panel design and wiring. The increased relay setting flexibility is accompanied by an increase in setting complexity that requires proper care to avoid setting errors.

(c) Some relays have experienced numerous software upgrades in a short period of time.

(d) Microprocessor relays have relatively shorter product life cycles because of the rapid advance in technology. As a result, a specific microprocessor relay model may only be available for a relatively short period of time. As a failure may require replacement rather than repair, it may not be possible to use an exact replacement, which may require more engineering and installation work. Although less frequent testing may be required, when it is, it requires a higher level of training for the technician and more test equipment than is normally used with electromechanical relays in order to obtain the full benefit of all the features of the microprocessor relay.

Due to these reasons back up protection with conventional relays is provided with microprocessor relays in hydroelectric plants. Various protection elements of a Microprocessor based relay are shown in table 14.

Table 14 : Protection elements of a Microprocessor based relay

Symbol Description 21 Under Impedance 24 Over Fluxing 26 Field Winding Temp 27 Under Voltage 27NT 100% Stator E/F 32 Reverse Power 38 Bearing Temp 40 Loss of Field 46 Negative Phase Sequence 49 Stator Winding Temp 50BF Breaker Failure 50P Instantaneous Phase Over Current 50N Instantaneous Neutral Over Current 50/27 Unintentional Energisation at Stand Still 51P Time Delayed Phase Over Current 51N Time Delayed Neutral Over Current 51N Voltage Controlled Over Current 59 Over Voltage 59N Residual Over Voltage


64R Restricted E/F 78 Pole Slipping Protection 81 Over/ Under Frequency 87G Generator Differential CTS Current Transformer Supervision VTS Voltage Transformer Supervision

3.3.2.3.2 Protection relays for SHP

(i). The application of relays must be coordinated with the partitioning of the electrical system by circuit breakers, so that least amount of equipment is removed from operation following a fault, preserving the integrity of the balance of the plant’s electrical system.

(ii). Generally, SHP Owners protection engineer will coordinate with the grid owners protection engineer to recommend the functional requirements of the overlapping zones of protection for the main transformers and high voltage bus and lines. The grid owners protection engineer will determine the protection required for the station service transformers, main unit generators, main transformers, and powerhouse bus.

(iii). Electromechanical protective relays, individual solid state protective relays, multi-function protective relays, or some combination of these may be used for protection system requirements.

(iv). Individual solid state protective relays and/or multifunction protective relays offer a single solution for many applications plus continuous self diagnostics to alarm when unable to function as required. Multi-function protective relays may be cost-competitive for generator and line protection where many individual relays would be required.

(v). When multi-function relays are selected, limited additional backup relays should be considered based upon safety, cost of equipment lost or damaged, repairs and the energy lost during the outage or repairs.

(vi). When redundancy is required, a backup protective relay with a different design and algorithm should be provided for reliability and security.

(vii). Generators, main transformers, and the high voltage bus bar are normally protected with independent differential relays (above 1000 kW unit size).

3.4 DEVICES USED IN A TYPICAL PROTECTION SYSTEM

The designer must balance the expense of applying a particular relay against the consequences of losing a generator. The total loss of generator may not be catastrophic if it represents a small percentage of the investment in an installation. However, the impact on service reliability and upset to loads supplied must be considered. Damage to equipment and loss of product in continuous processes can be dominating concern rather than generating unit. Accordingly there is no standard solution based on MW-rating. However, it is rather expected that a 100 kW, 415 V hydro machines will have less protection as compared to 25 MW base load hydro electric machine.


With increasing complications in power system, utility regulation, stress on cost reduction and trends towards automation, generating unit protection has become a high focus area. State of the art, micro processor based protection schemes offer a range of economical, efficient and reliable solution to address the basic protection and control requirements depending upon the size and specific requirement of the plant.

3.4.1 Requirements of Protection of Turbine for SHP (up to 3 MW)

It is given in table 15:

Table 15 : Protection of turbine

S. No. Element Alarm & annunciation Trip a. Speed rotation Alarm& annunciation Immediate

tripping b. Oil levels in bearing Only alarm& annunciation c. Circulation of lubricants Alarm& annunciation Immediate

tripping d. Oil level of the governing system Only alarm& annunciation e. Oil level of speed increaser

(if provided) Only alarm& annunciation

f. Bearing temperatures Only alarm& annunciation g. Oil temperature of governing system Only alarm& annunciation h. Oil temperatures of speed increasers Only alarm& annunciation i. Oil pressure of governing system Alarm& annunciation Immediate

tripping j. Pressure of cooling water Alarm& annunciation Immediate

tripping Applying brakes at a particular speed (30% of full speed) is done to reduce time to achieve stand still position of machine. It is recommended two independent devices must be provided for over speed shut down on larger machines. One for alarm mostly at 110% and other for tripping at 140%.

3.4.2 Requirements of Protection of Generator

Protection of generator is given in table 16.

Table 16 : Protection of generator

S. No.

Element Alarm & annunciation Trip

a. Stator temperature First alarm and annunciation

Then tripping

b. Over current (stator and rotor)

Alarm and annunciation Immediate tripping


S. No.


c. Earth fault with current limits (stators & rotor)


d. Maximum and minimum voltage


e. Power reversal


f. Over/ under frequency


g. Oil level in bearing sumps


h. Pad & oil temperature of bearings First alarm and annunciation

Then tripping

i. Cooling air temperature First alarm and annunciation

Then tripping

It is advisable to provide heating arrangement to prevent condensation in generator. 3.5 GENERATOR PROTECTION SYSTEM AND RELAY SELECTION 3.5.1 Categorization

In view of the economy and plant requirements generator protection for small hydropower stations is categorized a follows:

a) Generator size up to 100 kW b) Generator size above100 kW and up to 5000 kW c) Generator size above 5000 kW

3.5.2 Transient overvoltage and surge protection

Transient over-voltages and lightning surges are controlled by lightning arrestors. Surge capacitors are provided to restrict rate of rise of surge voltages and their magnitudes. Every generator is provided with a set of lightning arrestors / surge diverter of appropriate rating and generated voltage.

3.5.3 Protection for Micro hydro systems (up to 100 KW)

Monitoring and Protection as recommend in Micro Hydro Quality Standards issued by AHEC, IITR, be provided which is reproduced in table 17.


Table 17 : Monitoring and protection scheme

S. No.

Description Recommendations for MHP above 50 KW and up to 100kW

1 Switchgear/Earth fault protection

MCB/MCCB for O/C protection Provide Earth leakage circuit breaker (ELCB) /Residual current operated circuit breaker

2 Protection-Generator Stator temperature Stator over current Over/under voltage Over/under frequency Phase unbalance Reverse power Bearing temperature

3 Protection-Turbine Over speed Bearing temperature

Note: Use of DC source for control, monitoring and protection in MHP is costlier option as such AC operated protection system is adopted (e.g. AC with shunt trip coil of generator breaker) 3.5.4 Protection for Generating Units above 100 kW and up to 5 MW 3.5.4.1 Turbine

Requirements of Protection of Turbine are given in table 18:

Table 18 : Requirements of Protection of Turbine S. No.

Element Alarm & annunciation

Trip

a. Speed rotation Alarm& annunciation Immediate tripping b. Oil levels in bearing Alarm& annunciation

first Then tripping

c. Circulation of lubricants Alarm& annunciation Immediate tripping d. Oil level of the governing system Alarm& annunciation

first Then tripping

e. Oil level of speed increaser (if provided)

Alarm& annunciation first

Then tripping

f. Bearing temperatures Alarm& annunciation first

Then tripping

g. Oil temperature of governing system


Then tripping

h. Oil temperatures of speed increasers


Then tripping

i. Oil pressure of governing system Alarm& annunciation Immediate tripping j. Pressure of cooling water Alarm& annunciation Immediate tripping


It is recommended that two independent over speed shut-down devices be used on larger units which might not be designed for continuous runaway.

3.5.4.2 Generator

Requirements of Protection of Generators are given in table 19

Table 19 : Requirements of Protection of Generator

S. No.


a. Stator temperature First alarm and annunciation Then tripping b. Over current (stator and rotor) Alarm and annunciation Immediate tripping c. Earth fault with current limits

(stators & rotor) Alarm and annunciation Immediate tripping

d. Maximum and minimum voltage Alarm and annunciation Immediate tripping e. Power reversal Alarm and annunciation Immediate tripping f. Over/ under frequency Alarm and annunciation Immediate tripping g. Oil level in bearing sumps Alarm and annunciation Immediate tripping h. Pad & oil temperature of bearings First alarm and annunciation Then tripping i. Cooling air temperature First alarm and annunciation Then tripping

It is advisable to consider differential protection when the size of the generator and/or its environment justifies it. The instruments and devices generally recommended for monitoring and protection are as follows: voltmeter, ammeter, wattmeter, energy meter, power factor meter, tachometer, hours of operation counter, synchronizer, water-level and/or pressure indicator, turbine wicket gate position indicator, emergency stop device, short-circuit current protection, over current protection, reverse power relay, frequency monitor, voltage monitor, bearing monitor. Typical single line diagram for Asynchronous and synchronous generators are attached as figure -17 and figure-18 respectively based on recommendations by IEC: 61116 for SHP up to 5 MW units.

3.5.5 Protection for generating Unit above 5 MW and up to 25 MW

The following protection may be provided by using integrated numerical generator protection relay on generator, generator transformers and feeders. Back up electromagnetic relays with instrument transformers may be provided as mentioned below: Typical single line diagram is at figure-19 and unit metering and relaying is shown in figure-20.


Fig. 17 : Typical single line diagram for asynchronous generators


Fig. 18 : Typical single line diagram for synchronous generators


Fig. 19 : Typical Single Line Diagram for generating Units above 5MW

HV CIRCUIT BREAKER

LEGEND

NOMENCLATURE

LINK

LIGHTNING ARRESTOR

41G

POTENTIAL TRANSFORMER

40 -------- LOSS OF EXCITATION RELAY

FUSE

CURRENT TRANSFORMER

TRANSFORMER

EARTH

ISOLATING SWITCH

EXCITATION BREAKER WITHDISCHARGE RESISTOR

52-3

33/66/132 kV BUS

11 KV BREAKER

52-5


CT

CT

G1

PS

GENERATOR-

52-1

GENERATORTRANSFORMER-1

11-1


G2GENERATOR-2

52-2

11-2

P.T.

P.T.

P.T.

41G

41G -------- EXCITATION BREAKER

45G -------- FIELD SURGE PROTECTION51 -------- OVER CURRENT RELAY

51V -------- OVER CURRENT VOLTAGE RESTRAINT RELAY51D -------- DIRECTIONAL OVER CURRENT RELAYE/F -------- EARTH FAULT RELAY59 -------- OVER VOLTAGE RELAY63 -------- BUCHHOLZ RELAY

64F -------- ROTOR EARTH FAULT RELAY64G -------- STATOR EARTH FAULT RELAY64T -------- BACKUP POWER SYSTEM E/F RELAY

87G -------- GENERATOR EARTH FAULT RELAY87GT -------- GEN. TRANSFORMER E/F RELAY

25 -------- CHECK SYNCHRONISING46 -------- NEGATIVE SEQUENCE RELAY

45G

PS

CT

CT5P10 5P10

PS

PSCT

CT

CT

CT

CT

EXCITATIONCONTROL

CT

CT

RECTIFIERBRIDGE

L.A.

CTCORE-1, 5P10

P.T.

64T

CT

64T

CT 5P10

GENERATORTRANSFORMER-2

RECTIFIERBRIDGE

CT

11 KV CIRCUITBREAKER

CORE-2, METERINGCT

41G

OUTGOING LINES

52-6

ACC.CLASS 1-0

L.A.

87GT

51

87GT

51

87GT

P.T. P.T.

TO P.T.

EXCITATIONCONTROL

TO P.T.

///

DG SET

SATTAION AUX. T/F

PS CLASS FOR BUSDIFFERENTIAL

CTCORE-1, 5P10

CORE-2, METERINGCT

ACC.CLASS 1-0

PS CLASS FOR BUSDIFFERENTIAL

/ //


OUTGOING LINES


Fig. 20 : Typical Unit Metering Single Line Diagram for generating Units above 5MW

..

.

...

41G

THYRISTORBRIGES

S.S.


RESISTOR

64G

TURBINEGUIDER.T.D.

BEARING

A3

PF

VSV KW

V

L

RUN INC

SYN

SYN. PANEL

RECT

63QTH

38THTTHERMOSTAT

R.T.D.

GENERATOR GUIDE&THRUST BEARING

87G

86 EA

RATED 15 SEC.

TURBINE SPEEDNO LOADAND ALARM

TURBINE SHUTDOWN WITH ALARM

MISC

38 63 48

63TX

63T

FIRSTSTAGEALARM

86 EB

, PENSTOCK GATE AND ALARMCLOSURE


86 MA

86 MB

59

LDC

VAR.COMP

FROM EXCITOR 2

MANNUALKVAR

TO 86 EB

51 EX

38-2 5P 10

CT

11 KVGENERATORBREAKER

GENERATORS

TRIP 52-1, & 41G

AND ALARM

MISC

S.S.

S.S.

.

L

V

F F

STATICEXCITATIONVOLTAGEREGULATORAND CONTROL

33 K.V. BUS

11-1

S.S.

SYNCHRONISINGSOCKET

G

SY

NC

H.

DOWN

41 GTRIP 52-1 &

EQ

UIP

ME

NT

FRO

M B

ATT

ER

Y

31

FIE

LDFL

AS

HIN

G

38QB

39V33AB

26G63FG

71QBH/L

71QBH/L

26GS

C.T.

LINK

60

BLOCKS 50/51V& 40 ON LOSSOF RELAYPOTENTIAL

SURGEARRESTOR

51V 46

59

64F

86 EBTO

V

OER

A

12

38TG

26AO/AI

38QB

33CW/80CW

41 GTRIP 52-1 &

TURBINE SHUT41 GTRIP 52-1 &

DOWNTURBINE SHUT

PTPT

FF

PSCT

2.COMMON TRIPPING RELAYS FOR SIM ILAR

RELAYS

TEMPERATURE

3.TRIPPING BLOCK DIAGRAM DOES NOT

DETECTORS)

EQUIPMENT ORDERED

4.DETAILS OF R.T.D. (RESISTANCE

.

RELAYS FOR DISCRIMINATION OF FAULTS ARE

FUNCTIONS WILL BE PROVIDED WITH LOCK

FIRST STAGE ALARMS

(C) TURBINE GUIDE BEARING - 2 NO.

(A) GENERATOR STATOR WINDINGS - 12 NO.

ACTUAL

INDIVIDUAL CIRCUITS OF COMMON TRIPPINGPROPOSED TO BE PROVIDED IN THE

(B) GENERATOR THRUST BEARING - 2 NO.

OUT FACILITIES, SIGNAL TYPE CURRENT

1.THE SCHEME MAY BE MODIFIED TO SUIT

INCLUDE

ARE AS UNDER :

NOTES

5. UNIT-2 IS SAME AS UNIT-1

OVER VOLTAGE RELAY

LCD

SUPERVISORY

51 H

27L

RELAY

VAR METER

62L62

64F

WATT HOUR METER

81HH.V. SYSTEM STAND BY GROUND FAULT64T

81L

50/51DN

INSTANTANEOUS TIME OVERCURRENT

ANNUNCIATOR RELAY

A AMMETER

94

59

WM

INSTRUMENTRECT

TZ

VARM

86H

LINE DROP COMPENSATION

51 EX

66 K.V. SYSTEM

30

86 EX

SUPV.

GENERATOR TRANSFORMERDIFFERENTIAL RELAY

LOCKOUT RELAY

V

WHM

LOCKOUT RELAY

UNDERVOLTAGE RELAY

LOW FREQUENCY RELAY

DIRECTIONAL OVERCURRENTAND GROUND FAULT RELAY

PHASE RELAY

EXCITERS

OVER EXCITATION RELAY

52-1

PAR

GENERATOR FIELD BREAKER

FM

WATT METER

GENERATOR TRIP RELAY

TIMING RELAY

TRANSDUCER

87GT

66 K.V. BREAKER

OER

INSTANTANEOUS TIME OVERCURRENT

FREQUENCY METER

PARALLEL COMPENSATION

GROUND VOLTAGE RELAY - FIELD

COMP

TEMPERATURE MEASURINGAND RECORDING

VOLT METER

VS

-DO-

41G

METERING

HIGH FREQUENCY RELAY

EXCITATION RELAY31

VOLT METER SWITCH

25

CENTRIFUGAL SPEED SWITCH

CHECK SYNCHRONISING RELAY

12

63 T63 TX

LOCKOUT RELAY MECH. GROUP "A"

GENERATOR DIFFERENTIAL RELAY

LOCKOUT RELAY ELECT. GROUP "A"LOCKOUT RELAY ELECT. GROUP "B"

LOCKOUT RELAY MECH. GROUP "B"

GROUND VOLTAGE RELAY - STATOR64G

87G86 MB

86 EB86 EA

86 MA

38THT THRUST BEARING TEMPERATURE38QB BEARING OIL TEMPERATURE

71QBH/L BEARING OIL LEVEL(HIGH/LOW)

63QTH THRUST BEARING HIGH PRESSURE OILSYSTEM START INTERLOCK/FAILURE ALARM

63FG FIRE EXTIGUISHING SYSTEM OPERATION

26G TEMPERATURE DETECTORS FORFIRE PROTECTION SYSTEM

33AB AIR BRAKE POSITION INDICATION

26GS STATOR WINDING TEMPERATURE

26AU/AI AIR COOLER (OUTLET/INLET)AIR TEMPERATURE

33CW/80CW COOLING WATER VALVE POSITION/FLOW

38GT GUIDE BEARING TEMPERATURE

REVERSE POWER RELAY32

38 BEARING TEMPERATURE DEVICE

40 FIELD FAILURE RELAY

NEGATIVE PHASE SEQUENCE RELAY4647 PHASE SEQUENCE CHECK RELAY

(FOR SYNCHRONIZING)INCOMPLETE SEQUENCE RELAY48TARNSFORMER OVERCURRENT RELAY50/51 T

51V INSTANTANEOUS OVERCURRENTWITH VOLTAGE RESTRAINT RELAYVOLTAGE BALANCE RELAY60

GOVERNOR LOW OIL PRESSURE SWITCH63

RELEASE CO2,

TO 86 EB

52-1 BREAKER

63T

38T

5P10

CT

TRANSFORMERGEN.

64T

12G

12G ELECTRICAL OVERSPEEDC RELAY

38-2

65SN65SL

SOLENOID SPEED NO LOADSOLENOID SHUT DOWN

LINK

5P10

CT

12G12

MAIN TANK OVER PRESURE SWITCHAUXILIARY RELAY

PS

CT

CT

CT

NOMENCLATURE

45F FIELD SURGE PROTECTION

64F ROTOR EARTH FAULT RELAY

FM

KWH

50/51

40 32

2547

27V

87 GT

87 GT

250 kVA

51/64

C.T.

11/.415 kV

EX.CONTROL

TO P.T.

87T

TRANSFORMER DIFFERENTIAL RELAY87T

121

2


3.5.5.1 Various protections of Generator These are listed as below:

(i) Generator Differential Protection (87G) (ii) Negative Phase Sequence (46) (Phase Unbalance) (iii) Generator Reverse Power Protection (32) (iv) Voltage Restrained Over Current Protection (51V) (v) Stator Earth Fault Protection (64 G) (vi) Loss Of Excitation Protection (40) (vii) Over /Speed (electrical) Protection (12G) (viii) Rotor Earths Fault Protection (64R) (ix) Over Voltage Protection (59) (x) Fuse failure Protection (97) on PTS (xi) Under voltage (27) (xii) Check synchronizing

Following additional back up electromagnetic/ static relays from different set of CTs and PTs be also provided. (i) Voltage restraint over current relay (ii) Stator earth fault

Following Mechanical Protections may be provided as apart of digital control system

(i) Embedded Temperature detector (PT-100) in stator core and in bearing for indication, alarm, recording and shut down of the unit.

(ii) Governor oil pressure low. (iii) Over speed mechanical for normal and emergency shutdown. (iv) For large generators, fire protections system will use CO2 as the quenching

medium which will operate automatically. Hot spot/ smoke detectors are provided all around the periphery of generator winding. Bank of CO2 cylinders with control panel etc. are provided common for all the generators. The individual pipes let the CO2 enter in the faulty generator and quench the fire. Generator is isolated from the bus bar and machine stopped. The system is more effective in closed cycle cooling systems of generators.

3.5.6 Numerical Generator Protection Relay

Multi function Digital Generator protection relays providing flexible, integration of protection, control, monitoring and measurement functions from small generators up to large generators are now available. Some of the multifunctional Generator Protection Relays are discussed below.

Multifunction Digital Generator Protection Relays

Typical Functional Overview - Numerical Generator Protection Relay is shown in figure-21 and summarized in table 20.


Fig. 21 : Typical Functional Overview - Numerical Generator Protection Relay

Cat.-I may be used for small generators not requiring differential protection; Cat.-II can be used for SHP generators up to 25,000 kW.

Table 20 : Summary of numerical relay protection

Device

No. Functions overview Cat-I Cat-II

Settings 87 Differential

Inter turn (split phase) - -

1 1

50/51/67 Directional/non directional, instantaneous/ time delayed phase over current

4 4

50N/51N Non directional, instantaneous/ time delayed phase ground fault

2 2

67N/67W Sensitive directional earth fault/watt meteric ground fault 1 1 64 Restricted ground fault 1 1 51V Voltage dependant over current 1 1


Device No.

Functions overview Cat-I Cat-II Settings

21 Under impedance 2 2 59N Neutral voltage displacement/residual overvoltage, inter

turn – measured (M), derived (D) 2M/2D 2M/2D

27/59 Under/over voltage 2/2 2/2 81U/81O Under/over frequency 2/4 2/4 81AB Turbine abnormal frequency 6 6 32R/32L/32O

Reverse/Low Forward/Over power 2 2

40 Loss of field 2 2 46T Negative phase sequence thermal 2 2 46OC Directional/Non directional, negative phase sequence over

current 4 4

47 Negative phase overvoltage 1 1 49 Stator thermal overload 2 2 24 Over fluxing 5 5 78 Pole slipping - 1 27TN/59TN

100% stator earth fault 3rd harmonic neutral under/over voltage)

- 1

50/27 Unintentional energisation at standstill - 1 50BF CB fail 2 2 Current transformer supervision 1 1 Voltage transformer supervision 1 1 RTDS x 10 PT 100 Option Option

Schematic diagram of a 4 x 4 MW SHP with multi function generator relays is shown in fig- 22 and generator control panel is shown in fig-23.

3.6 GENERATOR TRANSFORMER PROTECTION 3.6.1 132 kV & 72.5 Class transformers

Generator transformers up to 132 kV class may be used. The protection in SHP for 25 MW protection for transformers up to 132 kV class as per Central Board of Irrigation and Power Manual on transformers is as follows: i) Percentage biased differential relay (without harmonic restraint). ii) High speed differential relay with harmonic restraint feature ) for power

transformer of capacities above 100 MVA iii) Back up over current relay on primary side iv) Back up over current and earth fault relay on the secondary side v) Oil temperature indicator with alarm and trip contact. vi) Buchholz relay with alarm and trip contact vii) Winding temperature indicator with alarm and trip contact. (For transformer

having capacity up to 10 MVA)


viii) Winding temperature indicator with three contacts one each for alarm, trip and control of fans (for transformer having capacities above 10 MVA)

ix) Magnetic oil gauge with low level alarm contacts x) Lightning arrestors on both primary and secondary sides when the transformer is

located outdoors and is connected to overhead lines xi) Oil surge protection for on load tap changer diverter tank with trip contact xii) Pressure release device with trip contact for transformer rated 100 MVA and

above

Fig. 22 : Typical Multifunction Generator Relays


Fig. 23 : Typical Generator Control Panel

3.6.2 36 kV Class Transformers

i) 36 kV class power transformer of capacities ranging from 3.15 MVA and above ii) Percentage biased differential relay (without harmonic restraint) for power

transformer up to 10 MVA. iii) High speed differential relay with second harmonic restraint differential device

for power transformer of capacities above 10 MVA iv) IDMT type over current relay with high set elements on the primary side v) IDMT type over current and earth fault relay on the secondary side


vi) Oil temperature indicator with alarm one electrical contact for alarm or trip contact.

vii) Buchholz relay with alarm and trip contact viii) Winding temperature indicator with three electrical contacts for (a) alarm (b) trip

& (c) Fan control for transformers above 10 MVA ix) Lightning arrestors on both primary and secondary sides when the transformer is

located outdoors and is connected to overhead lines x) Oil surge protection for on load tap changers (OLTC) (if provided) diverter tank

with trip contact xi) Pressure release device with trip contact for transformer rated 100 MVA and

above

3.6.3 12 kV Class transformers

i) IDMT over current relay on the 11 kV side ii) Over current and earth fault relay on the secondary side iii) Buchholz relay with alarm and trip contact iv) Oil temperature indicator with alarm and trip contact. v) Lightning arrestors on both primary and secondary sides when the transformer is

located outdoors and is connected to overhead lines

3.6.4 Transformer Differential Protection by Numerical Relays

Typical multifunction digital differential protection relay with IEC protocol with functionalities available for two winding transformer is given in table 21 and shown in figure 24. Three winding transformers are not in general used in SHP.

Table 21 : Typical multi function digital differential protection relay

Functions Overview Type

Device No

Description 1 2

87 Differential protection 2 wind. 2 wind. 87N Restricted earth fault protection - 2 50 Definite – time O/C protection 2 2 51 Inverse – time O/C protection 2 2 49 Thermal overload protection 1 1

27,59 Over/under voltage protection - 1 81 Over/under frequency protection - - 24 Over excitation protection - - Measuring circuit monitoring 2 2 Programmable logic 1 1


Fig. 24 : Typical Functional Overview – Transformer Differential Protection Suitable back up conventional protection should be provided. Numerical protection proposed for 6 MVA, 11/33 kV generator transformer is shown in Fig-25.

3.7 LINE PROTECTION 3.7.1 11 kV and 33 kV Line Protection

Generator Connected In Parallel to Grid

Whenever generators are running parallel to grid, a synchronizing & grid islanding scheme will be required. This scheme will help in synchronizing the generator to the bus and opening the incomer breaker of the plant whenever there is a severe grid disturbance, thus protecting the generator from ill effects of disturbed grid.

Grid disturbances / faults

(i) Over current and directional earth fault, (ii) Under-voltage / Over-voltages (iii) Under-frequency/Over-frequency (iv) Rapid fall/ rise of frequency (df / dt), (v) Grid failure or other faults


Fig. 25 : Schematic Drawing – 6 MVA, 11/33 kV Gen. Trans. Protection Single Line Diagram


Generator may not be able to operate below a certain power-factor. At low power-factor, reverse reactive power flow may damage the generator.

Fig. 26 : Typical SHP Grid Interconnection – Two Terminal 66 kV (Short & important) Line Protection

3.7.2 66 kV & 132 kV Feeder Protection

Primary Protection: Pilot aided (carrier communication) High speed 3 step directional distance protection for phase to phase and phase to earth and three phase faults (digital) or phase comparison type carrier relaying for short important lines.

Secondary Protection: Directional over current and earth fault relays (static).

A typical example is shown in figure-26 for 66 kV line interconnecting grid by short lines. Numerical protection for a33 kV line protections is shown in figure 27.

3

66KV

T Z

5 P 10

/

67N

81L

11O V.

66kV FEEDER-1

P.T.

Vs

V

KWH

52-3

81H

CLASS 1

27

62

TO UNIT

110V

62

3

F

/

V

SUPV.

KVAR

/3

67

WAVE TRAP

/

KV

KW

Vs

SYNCHRONISING

NOMENCLATURE

A

/

185TRIPS 52-3

LEGEND

LIGHTNING ARRESTOR

CURRENTTRANSFORMER

FUSE

RECORDINGINSTRUMENT

A


VOLTMETER

AMMETER

V

EARTH


ISOLATORCURRENTTRANSFORMER200/1

5 P 10

PS

40 LOSS OF EXCITATION RELAY

DIRECTIONAL OVER CURRENTRELAY67TIMING RELAY62FREQUENCY RELAY81L/H (LOW, HIGH)

185DIRECTIONAL EARTH FAULT RELAY67NFREQUENCY METERFM

POWER FACTOR METERPFTZ TRANSDUCER

POTENTIALTRANSFORMER

PS

PHASE COMPARISON RELAY

PLCC

LMU

25

50Z

UNDER VOLTAGE RELAY27

25 CHECK SYNCHRONIZING RELAY

LOCAL BREAKER BACKUP PROTECTION50Z

CVT


Fig. 27 : Schematic Drawing for 33 kV Line Protection for 4 x4 MW Project


3.8 RECOMMENDATIONS FOR PROTECTION AND RELAYING

Recommendations are as summarized in table 22 below:

Table 22 : Recommendations for protection and relaying

Equipment Unit Capacity in kW Unit capacity above 50 kW and up to 100 kW

Unit capacity Above 100 kW and up to 5000 kW

Unit capacity Above 5000 kW

Generator a. Stator over current{voltage restraint)

b. Stator earth fault c. Reverse power d. Over/under voltage e. Over/ under

frequency f. Phase unbalance.

a. Stator over current{voltage restraint)

b. Stator earth fault c. Reverse power d. Phase unbalance e. Field failure f. Over/ under voltage g. Over/ under frequency h. Oil level in bearing sump i. Stator temp. high j. Bearing temp high k. Fuse failure Protection on

PTs l. Check synchronizing m. Differential protection for

501 kW and above n. Rotor earth fault –stage I for 1001 kW and above o. Over excitation for 1001

kW and above

a. Differential protection b. Rotor earth fault –

stage-I/stage-II c. Stator over

current{voltage restraint)

d. Stator earth fault e. Reverse power f. Phase unbalance g. Field failure h. dv/df protection i. Over excitation prot. j. Over/ under voltage k. Over/ under frequency l. Fuse failure Protection

on PTs m. Check synchronizing n. Stator temp. high o. Oil level in bearing

sump p. Bearing temp high

Turbine

a. Over speed b. Bearing temp.

a. Oil level low in OPU b. Over speed c. Oil pressure low in OPU d. Turbine bearing temp e. For Units of 1001kW -5000

kW f. Stator over current {voltage

restraint) g. Stator earth fault

a. Cooling water pressure low

b. Oil level low in OPU c. Over speed d. Oil pressure low in

OPU e. Cooling water flow

low f. Bearing temp. g. Stator over

current{voltage restraint)

h. Stator earth fault i. Reverse power j. Field failure

k. Phase unbalance Back up protection in addition to numerical relays (Static relays should be used)


SECTION-IV METERING AND MONITORING

4.1 METERING AND MONITORING Monitoring of operating parameters of the generating unit and their auxiliaries is very important for the life and optimum utilization of available discharge for generation. The efficient running of unit requires regular monitoring. The primary input data and generation output data are monitored periodically. Monitoring is data acquisition and annunciation. Annunciation comprises visual and audible alarm. Audible alarm is to alert the operator and visual alarm is to indicate faulty circuit / equipment. The details of data required for monitoring performance of a generating station are as shown in table 23 below:

Table 23 : Data required for monitoring

Hydraulic system Electro-mechanical S. No

Parameters S. No

Operating Parameters S. No

Other Parameters

i. ii. iii. iv. v. vi.

Water conductor River discharge Fore-bay level Power channel discharge Spill way discharge Penstock pressure Tail water level

1 i. ii. iii iv.

Turbine and accessories Speed Guide vane opening & limits (percent) for reaction turbine Runner blade opening in Kaplan Turbine (percent) Nozzle opening in impulse turbine (percent)

i. ii. iii. iv v. vi vii.

Pressure and levels in oil pressure system Bearing temperatures (oil & pads) Oil level in bearing sumps (if provided) Cooling water pressure and temperatures Clean water pressure for shaft gland Vibration in shaft for large machines( optional) Status of inlet and other valves.

2 i. ii. iii. iv.

Generator &accessories Generated power (kW or MW) Generated units (kWh) Kilovolt ampere (kVA) Kilovolt ampere reactive (kVAR)

i. ii. iii.

Stator winding temperature Bearing temperatures Cooling water and air temperatures


v vi vii viii.

Power factor (PF) Frequency (Hz) Excitation voltage (Volts) Excitation current (Amp)

3

i. ii. iii. iv.

Transformer Winding temperature Oil temperature Oil level Cooling water temperature and pressures

i. ii. iii.

Tap position HV/LV current Primary/ secondary voltage

4 i. ii. iii. iv. v.

Grid system & transmission line Grid voltage Grid frequency Power export/import (kW) Current (Amp) Kilowatt hour (kWh) export / import

5 i. ii. iii. iv. v. vi vii. viii.

Station auxiliaries Voltage and current on LT AC system Kilowatt hour (kWh) Diesel generator running hour, kWh & other parameters Drainage & dewatering system a. Running hours of pumps b. Water level in sump Fire extinguisher – periodical testing Battery set- Regular monitoring as per manufacturers recommendations Battery chargers & distribution boards – voltage current etc. OPU system a. Running hours of pumps b.Level in pressure accumulators c. Pressure of oil


4.2 REQUIREMENTS OF MONITORING SYSTEM 4.2.1 Instrument Transformers & Sensors

(i). CTs & VTs Current and voltage transformers of rated voltage and appropriate ratio, class of accuracy are selected as per the requirement of the system. (ii). Sensors The sensors for temperatures, pressures, levels and speed are installed at the proper location.

4.2.2 Indicating Meters Analogue type of meters, separate for each parameter with selector switches etc were being used earlier installed on control panels. Now a days digital meters are being used for such parameters. Digital multifunction meters are now in use, only one meter provides several parameters on selection, as well as provides routine display.

4.2.3 Temperature Scanners Digital temperature scanners indicating the temperatures of stator winding, bearing pads, oil coolers etc. are provided and installed on the generator control panels. These scanners get the signals from the sensor installed at specific locations preferably through screened cables.

4.2.4 Indicating Lamps Indicating lamps of suitable colours as per code and practices should be provided on control panels for indication status of machine and various auxiliaries, pumps, electrical equipment like breaker, isolator, AC/DC supply system etc. Lists of such indication and relays are enclosed as Annexure-1 and Annexure-2.

4.2.5 Alarm & Annunciations The protection system relays and auxiliary relays also provide signals to alarm and annunciation system. A set of annunciation windows are provided on control panels for each fault clearing relay with accept test and reset facility through push buttons. Alarm and trip annunciation indicate the fault and advise operating personnel of the changed operating conditions.


4.3 RECOMMENDATIONS FOR METERING AND MONITORING OF SHP

These are given in table 24 below:

Table 24 : Recommendations for metering and monitoring

Equipment Installed Capacity in kW

Unit capacity above 50 KW and up to

100 kW

Unit capacity above 100 kW and up to

5000kW

Unit capacity above 5000 kW

Generator a. Voltage, current frequency, kWh, kW, Pf

b. Stator Temp. c. Bearing temp.

a. Voltage, current, frequency, kWh, kVAR, PF

b. Stator Temp. c. Bearing Temp. d. Oil level in bearing

sump. e. Lub. Oil pressure f. Isolator status g. Breaker status

a. Voltage, current, frequency, kWh, kVAR, PF

b. Stator Temp. c. Bearing Temp. d. Oil level in bearing sump. e. Lub. Oil pressure f. Isolator status g. Breaker status

Turbine

a. Turbine speed b. Bearing Temp.

a. Turbine speed b. Bearing Temp. c. Oil pressure in OPU d. Oil level in OPU e. Penstock pressure f. Spiral pressure g. Fore bay level h. Tail race level i. Brake status j. Gear box oil

pressure( if provided

a. Turbine speed b. Bearing Temp. c. Oil pressure in OPU d. Cooling water pressure e. Oil level in OPU f. Penstock pressure g. Fore bay level h. Tail race level i. % Guide vane opening j. Runner blade

opening(Kaplan only) k. Needle opening

(Pelton/Turgo) l. MIV status m. Bye Pass Valve status n. Brake status o. Gear box oil pressure( if

provided

Excitation

a. Excitation Voltage b. Excitation current c. Excitation status

a. Excitation voltage b. Excitation current c. Excitation status


ANNEXURE-1

LIST OF GENERATOR PANEL INDICATION AND RELAYS

S. No. Designation Inscription Colours 1 L1 DC Supply on Yellow 2 L2 AC Supply on Red 3 L3 Generator Circuit Breaker Close Red 4 L4 Generator Circuit Breaker Open Green 5 L5 Generator Circuit Breaker Trip Amber 6 L6 Generator Circuit Spring Charge Blue 7 L7 Trip Coil Healthy Yellow 8 L8 DC Supply Failed Red 9 L9 Spare Red 10 R R Phase Bus Healthy Red 11 Y Y Phase Bus Healthy Yellow 12 B B Phase Bus Healthy Blue 13 IPB Immediate Action Trip Push Button Red 14 PB1 Controlled Action Shut Down Push Button Green 15 PB2 Spare Push Button Red 16 TS Temperature Scanner 17 DMF Digital Multi Function Meter 18 H Hooter Black 19 ANN Annunciator Black 20 T Test Push Button Black 21 A Accept Push Button Yellow22 R Reset Push Button 23 BAPB Bell Accepted Push Button 24 27 Under Voltage Relay 25 32P Reverse Power Relay 26 51V Voltage Controlled Over Current Relay 27 59 Over Voltage Relay 28 60 PT Fuse Failure Relay 29 64S Stator Earth Fault Relay 30 46 Negative Phase Sequence Relay 31 40 Loss of Field Relay 32 95 Trip coil Supervision relay 33 87G Generator Differential Relay 34 52G Generator Circuit Breaker 35 KWTR Kilowatt Transducer 36 BL Electrical Bell 37 86G1 Master Trip Relay 38 86G2 Master Trip Relay 39 86G3 Master Trip Relay 40 86G4 Master Trip Relay


ANNEXURE-2

LIST OF PROTECTION ELEMENTS IN MICRO PROCESSOR BASED RELAYS

Symbol Description 21 Under Impedance 24 Over Fluxing 26 Field Winding Temp 27 Under Voltage 27NT 100% Stator E/F 32 Reverse Power 38 Bearing Temp 40 Loss of Field 46 Negative Phase Sequence 49 Stator Winding Temp 50BF Breaker Failure 50P Instantaneous Phase Over Current 50N Instantaneous Neutral Over Current 50/27 Unintentional Energisation at Stand Still 51P Time Delayed Phase Over Current 51N Time Delayed Neutral Over Current 51N Voltage Controlled Over Current 59 Over Voltage 59N Residual Over Voltage 64R Restricted E/F 78 Pole Slipping Protection81 Over/ Under Frequency 87G Generator Differential CTS Current Transformer Supervision VTS Voltage Transformer Supervision

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